Edgar Filing: GRAN TIERRA ENERGY INC.

Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018



o		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)

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 ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post such files).

Yes ý No o

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 x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o
	Emerging growth company o

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. o

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

On July 30, 2018, the following number of shares of the registrant’s capital stock were outstanding: 391,175,023 shares of the registrant’s Common Stock, $0.001 par value.

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended June 30, 2018

Table of contents



		Page
PART I	Financial Information
Item 1.	Financial Statements	4
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	36

PART II	Other Information
Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 6.	Exhibits	38
SIGNATURES		39

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; 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; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict; our ability to execute business plans; the risk that 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; the risk that current global economic and credit market conditions may impact oil prices and oil consumption more than we currently predict, which could cause us to further modify our strategy and capital spending program; those factors set out in Part I, Item 1A “Risk Factors” in our 2017 Annual Report on Form 10-K and in our other filings with the Securities and Exchange Commission (“SEC”). The information included herein is given as of the filing date of this Quarterly Report on Form 10-Q with the SEC and, except as otherwise required by the federal securities laws, we disclaim any obligation or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

In this document, the abbreviations set forth below have the following meanings:



bbl	barrel	BOE	barrels of oil equivalent
bopd	barrels of oil per day	BOEPD	barrels of oil equivalent per day
Mcf	thousand cubic feet	NAR	net after royalty

Sales volumes represent production NAR adjusted for inventory changes. Our oil and gas reserves are reported NAR. Our production is also reported NAR, except as otherwise specifically noted as "working interest production before royalties." Natural gas liquids ("NGLs") volumes are converted to BOE on a one-to-one basis with oil. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy content of gas and oil. The rate is not necessarily indicative of the relationship between oil and gas prices. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

PART I - Financial Information

Item 1. Financial Statements

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations (Unaudited)

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
OIL AND NATURAL GAS SALES (Notes 3 and 7)	$	163,446		$	96,128		$	301,674		$	190,787

EXPENSES
Operating	35,059			27,208			61,324			51,145
Transportation	6,522			6,492			13,519			13,434
Depletion, depreciation and accretion (Note 3)	46,607			31,813			86,068			58,689
General and administrative (Note 3)	13,213			9,513			24,373			18,225
Equity tax	—			—			—			1,224
Foreign exchange loss	1,924			3,897			982			2,050
Financial instruments loss (gain) (Note 10)	4,768			(1,447		)	11,714			(6,886		)
Interest expense (Note 5)	7,375			3,331			12,870			6,426
	115,468			80,807			210,850			144,307

LOSS ON SALE	(292		)	(9,076		)	(292		)	(9,076		)
INTEREST INCOME	610			245			1,396			653
INCOME BEFORE INCOME TAXES (Note 3)	48,296			6,490			91,928			38,057

INCOME TAX EXPENSE
Current (Note 8)	4,827			1,772			17,116			9,189
Deferred (Note 8)	23,169			11,525			36,651			22,904
	27,996			13,297			53,767			32,093
NET AND COMPREHENSIVE INCOME (LOSS)	$	20,300		$	(6,807	)	$	38,161		$	5,964

NET INCOME (LOSS) PER SHARE
- BASIC AND DILUTED	$	0.05		$	(0.02	)	$	0.10		$	0.01
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)	391,054,204			398,585,290			391,173,460			398,795,023
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)	427,455,092			398,585,290			427,242,014			398,816,091

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)



	As at June 30, 2018			As at December 31, 2017

ASSETS
Current Assets
Cash and cash equivalents (Note 11)	$	125,807		$	12,326
Restricted cash and cash equivalents (Note 11)	2,836			11,787
Accounts receivable	63,030			45,353
Investment (Note 10)	32,654			25,055
Derivatives (Note 10)	930			302
Taxes receivable	62,689			40,831
Other current assets	14,423			9,591
Total Current Assets	302,369			145,245

Oil and Gas Properties (using the full cost method of accounting)
Proved	750,948			629,081
Unproved	423,808			464,948
Total Oil and Gas Properties	1,174,756			1,094,029
Other capital assets	3,440			5,195
Total Property, Plant and Equipment (Notes 3 and 4)	1,178,196			1,099,224

Other Long-Term Assets
Deferred tax assets	18,248			57,310
Investment (Note 10)	15,302			19,147
Other long-term assets (Note 11)	5,389			6,112
Goodwill (Note 3)	102,581			102,581
Total Other Long-Term Assets	141,520			185,150
Total Assets (Note 3)	$	1,622,085		$	1,429,619
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	126,726		$	125,876
Derivatives (Note 10)	27,157			21,151
Taxes payable	3,848			9,324
Asset retirement obligation	110			323
Equity compensation award liability (Note 10)	11,597			295
Total Current Liabilities	169,438			156,969

Long-Term Liabilities
Long-term debt (Notes 5 and 10)	398,130			256,542
Deferred tax liabilities	24,528			28,417
Asset retirement obligation	35,839			31,241
Equity compensation award liability (Note 10)	9,480			11,135
Other long-term liabilities	9,381			8,980
Total Long-Term Liabilities	477,358			336,315

Contingencies (Note 9)

Shareholders’ Equity
Common Stock (Note 6) (390,017,518 and 385,191,042 shares of Common Stock and 1,135,239 and 6,111,665 exchangeable shares, par value $0.001 per share, issued and outstanding as at June 30, 2018, and December 31, 2017, respectively)	10,295			10,295
Additional paid in capital	1,328,037			1,327,244
Deficit	(363,043		)	(401,204		)
Total Shareholders’ Equity	975,289			936,335
Total Liabilities and Shareholders’ Equity	$	1,622,085		$	1,429,619

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)



	Six Months Ended June 30,
	2018			2017
Operating Activities
Net income	$	38,161		$	5,964
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 3)	86,068			58,689
Deferred tax expense	36,651			22,904
Stock-based compensation (Note 6)	10,202			3,183
Amortization of debt issuance costs (Note 5)	1,513			1,225
Cash settlement of restricted share units	(360		)	(501		)
Unrealized foreign exchange loss	539			1,076
Financial instruments loss (gain) (Note 10)	11,714			(6,886		)
Cash settlement of financial instruments (Note 10)	(15,483		)	1,216
Cash settlement of asset retirement obligation	(369		)	(298		)
Loss on sale	292			9,076
Net change in assets and liabilities from operating activities (Note 11)	(37,994		)	(28,112		)
Net cash provided by operating activities	130,934			67,536

Investing Activities
Additions to property, plant and equipment (Note 3)	(157,088		)	(104,025		)
Property acquisitions	(3,100		)	(30,410		)
Net proceeds from sale of Brazil business unit	—			34,481
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit	—			4,700
Changes in non-cash investing working capital	(6,142		)	(627		)
Net cash used in investing activities	(166,330		)	(95,881		)

Financing Activities
Proceeds from bank debt, net of issuance costs (Note 5)	4,988			98,304
Repayment of bank debt (Note 5)	(153,000		)	(33,000		)
Proceeds from exercise of stock options (Note 6)	845			—
Repurchase of shares of Common Stock (Note 6)	(1,208		)	(10,000		)
Proceeds from issuance of Senior Notes, net of issuance costs (Note 5)	288,087			—
Net cash provided by financing activities	139,712			55,304

Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(69		)	(1,175		)

Net increase in cash, cash equivalents and restricted cash and cash equivalents	104,247			25,784
Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 11)	26,678			43,267
Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 11)	$	130,925		$	69,051

Supplemental cash flow disclosures (Note 11)

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Six Months Ended June 30,			Six Months Ended June 30,
	2018			2017
Share Capital
Balance, beginning of period	$	10,295		$	10,303
Repurchase of Common Stock (Note 6)	—			(4		)
Balance, end of period	10,295			10,299

Additional Paid in Capital
Balance, beginning of period	1,327,244			1,342,656
Exercise of stock options (Note 6)	845			—
Stock-based compensation (Note 6)	1,156			1,354
Repurchase of Common Stock (Note 6)	(1,208		)	(9,996		)
Balance, end of period	1,328,037			1,334,014

Deficit
Balance, beginning of period	(401,204		)	(493,972		)
Net income	38,161			5,964
Cumulative adjustment for accounting change related to tax reorganizations	—			124,476
Balance, end of period	(363,043		)	(363,532		)

Total Shareholders’ Equity	$	975,289		$	980,781

(See notes to the condensed consolidated financial statements)

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.

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, 2017, included in the Company’s 2017 Annual Report on Form 10-K, filed with the SEC on February 27, 2018.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2017 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

Revenue from Contracts with Customers

The Company adopted Accounting Standard Codification ("ASC") 606 Revenue from Contracts with Customers with a date of initial application of January 1, 2018 in accordance with the modified retrospective approach without using the practical expedients. Except for providing enhanced disclosures about the Company's revenue transactions, the application of ASC 606 did not have an impact on the Company’s consolidated financial position, results of operations or cash flows.

a) Significant Accounting Policy

The Company's revenue relates to oil and natural gas sales in Colombia. The Company recognizes revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Payment terms are generally within three business days following delivery of an invoice to the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents the Company's share and is recorded net of royalty payments to governments and other mineral interest owners.

The Company evaluates its arrangement with third parties and partners to determine if the Company acts as a principal or an agent. In making this evaluation, management considers if the Company obtains control of the product delivered, which is indicated by the Company having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by the Company from the transaction.

Tariffs, tolls and fees charged to other entities for use of pipelines owned by the Company are evaluated by management to determine if these originate from contracts with customers or from incidental arrangements.

In the comparative period, revenue from the production of oil and natural gas was recognized when the customer took title and assumed the risks and rewards of ownership, prices were fixed or determinable, the sale was evidenced by a contract and collection of the revenue was reasonably assured.

b) Significant Judgments

When determining if the Company acted as a principal or as an agent in transactions, management determines if the Company obtains control of the product. As part of this assessment, management considers detailed criteria for revenue recognition set out in ASC 606.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities". ASU 2016-01 addressed certain aspects of recognition, measurement, presentation and disclosure of financial instruments. ASU 2016-01 was effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. The implementation of this update did not impact on the Company’s consolidated financial position, results of operations or cash flows or disclosure.

In February 2018, the FASB issued ASU 2018-03, "Recognition and Measurement of Financial Assets and Financial Liabilities". ASU 2018-03 clarified certain aspects of the guidance in ASU 2016-01. ASU 2018-03 is effective for annual reporting periods beginning after December 15, 2017 and interim reporting periods within those annual reporting periods beginning after June 15, 2018. Early adoption is permitted upon adoption of ASU 2016-01.The amendments should be applied retrospectively with a cumulative-effect adjustment to the effective date of ASU 2016-01. The Company early adopted this update on January 1, 2018. The implementation of this update did not impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

Recently Issued but Not Yet Adopted Accounting Pronouncements

Leases

In January 2018, the FASB issued ASU 2018-01, "Land Easement Practical Expedient for Transition to Topic 842". ASU 2018-01 provides an optional transition practical expedient that, if elected, would not require an organization to reconsider their accounting for existing or expired land easements that were not previously accounted for as leases under Topic 840. The effective date and transition requirements for the amendment is the same as the effective date and transition requirements in Update 2016-02. The Company is planning to adopt ASU 2018-01 upon transition to ASU 2016-01 "Leases".

The Company is finalizing an assessment of its contract inventory using certain practical expedients to determine which contracts meet the definition of a lease. The next steps will include classifying leases as either financing or operating, establishing interest rates and determining the value of right-of-use lease assets and lease liabilities. The Company expects to apply the guidance of ASU 2016-02 using a modified retrospective transition approach.

3. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. Commencing 2018, the Company has one reportable segment based on geographic organization, Colombia. Prior to the sale of the Company's Brazil business unit effective June 30, 2017 and Peru business unit effective December 18, 2017, Brazil and Peru were reportable segments. The "All Other" category represents the Company’s corporate activities, Mexico activities and Brazil and Peru activities until the date of sale.

The following tables present information on the Company’s reportable segments and other activities:



	Three Months Ended June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	163,446	$	—		$	163,446
Depletion, depreciation and accretion	46,065		542			46,607
General and administrative expenses	7,213		6,000			13,213
Income (loss) before income taxes	51,029		(2,733		)	48,296
Segment capital expenditures	83,757		637			84,394

	Three Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	91,905	$	4,223		$	96,128
Depletion, depreciation and accretion	30,130		1,683			31,813
General and administrative expenses	5,229		4,284			9,513
Income (loss) before income taxes	21,598		(15,108		)	6,490
Segment capital expenditures	55,436		2,429			57,865

	Six Months Ended June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	301,674	$	—		$	301,674
Depletion, depreciation and accretion	84,564		1,504			86,068
General and administrative expenses	14,022		10,351			24,373
Income (loss) before income taxes	112,180		(20,252		)	91,928
Segment capital expenditures	156,318		770			157,088

	Six Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	182,369	$	8,418		$	190,787
Depletion, depreciation and accretion	55,065		3,624			58,689
General and administrative expenses	10,061		8,164			18,225
Income (loss) before income taxes	58,742		(20,685		)	38,057
Segment capital expenditures	98,276		5,749			104,025



	As at June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,176,540	$	1,656	$	1,178,196
Goodwill	102,581		—		102,581
All other assets	175,563		165,745		341,308
Total Assets	$	1,454,684	$	167,401	$	1,622,085

	As at December 31, 2017
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,096,833	$	2,391	$	1,099,224
Goodwill	102,581		—		102,581
All other assets	176,980		50,834		227,814
Total Assets	$	1,376,394	$	53,225	$	1,429,619

4. Property, Plant and Equipment



(Thousands of U.S. Dollars)	As at June 30, 2018			As at December 31, 2017
Oil and natural gas properties
Proved	$	3,014,725		$	2,810,796
Unproved	423,808			464,948
	3,438,533			3,275,744
Other	19,086			26,401
	3,457,619			3,302,145
Accumulated depletion, depreciation and impairment	(2,279,423		)	(2,202,921		)
	$	1,178,196		$	1,099,224

The Company used an average Brent price of $62.58 per bbl for the purposes of the June 30, 2018 ceiling test calculations (March 31, 2018 - $56.92, December 31, 2017 - $54.19).

5. Debt and Debt Issuance Costs

The Company's debt at June 30, 2018 and December 31, 2017 was as follows:



(Thousands of U.S. Dollars)	As at June 30, 2018			As at December 31, 2017
Senior notes	$	300,000		$	—
Convertible notes	115,000			115,000
Revolving credit facility	—			148,000
Unamortized debt issuance costs	(16,870		)	(6,458		)
Long-term debt	$	398,130		$	256,542

Senior Notes

On February 15, 2018, Gran Tierra Energy International Holdings Ltd. ("GTEIH"), an indirect, wholly owned subsidiary of the Company, issued $300 million of 6.25% Senior Notes due 2025 (the "Senior Notes"). The Senior Notes are fully and unconditionally guaranteed by the Company and certain subsidiaries of the Company that guarantee its revolving credit facility. Net proceeds from the sale of the Senior Notes were $288.1 million, after deducting the initial purchasers' discounts and commission and the offering expenses payable by the Company.

The Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

Before February 15, 2022, GTEIH may, at its option, redeem all or a portion of the Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2022 - 103.125%; 2023 - 101.563%; 2024 and thereafter - 100%.

Interest Expense

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



	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017		2018		2017
Contractual interest and other financing expenses	$	6,532	$	2,711	$	11,357	$	5,201
Amortization of debt issuance costs	843		620		1,513		1,225
	$	7,375	$	3,331	$	12,870	$	6,426

6. Share Capital

On May 1, 2018, Gran Tierra Exchangeco Inc., a subsidiary of the Company, announced that it had established a redemption date of July 5, 2018 in respect of all of its outstanding exchangeable shares. Effective July 5, 2018, all remaining outstanding exchangeable shares of record on July 4, 2018 were acquired for purchase consideration of one share of Gran Tierra common stock, and on July 9, 2018, the Company retired and canceled one share of Special A Voting Stock and one share of Special B Voting Stock, which held voting rights in connection with those exchangeable shares. As a result, no shares of Special A Voting Stock and Special B Voting Stock remain outstanding.



	Shares of Common Stock		Exchangeable Shares of Gran Tierra Exchangeco Inc.		Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2017	385,191,042		4,422,776		1,688,889
Options exercised	319,462		—		—
Shares repurchased and canceled	(469,412	)	—		—
Exchange of exchangeable shares	4,976,426		(3,287,537	)	(1,688,889	)
Balance, June 30, 2018	390,017,518		1,135,239		—

On March 7, 2018, the Company announced that it intended to implement a share repurchase program (the “2018 Program”) through the facilities of the Toronto Stock Exchange ("TSX") and eligible alternative trading platforms in Canada. Under the 2018 Program, the Company is able to purchase at prevailing market prices up to 19,269,732 shares of Common Stock, representing approximately 5.00% of the issued and outstanding shares of Common Stock as of March 8, 2018. Shares purchased pursuant to 2018 Program will be canceled. The 2018 Program will expire on March 11, 2019, or earlier if the 5.00% share maximum is reached.

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock option activity for the six months ended June 30, 2018:



	PSUs		DSUs	RSUs		Stock Options
	Number of Outstanding Share Units		Number of Outstanding Share Units	Number of Outstanding Share Units		Number of Outstanding Stock Options		Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2017	6,131,951		455,768	122,090		8,960,692		3.65
Granted	3,544,001		131,888	—		1,996,526		2.51
Exercised	—		—	(120,268	)	(319,462	)	2.65
Forfeited	(213,160	)	—	(1,822	)	(491,475	)	5.42
Expired	—		—	—		(171,854	)	6.15
Balance, June 30, 2018	9,462,792		587,656	—		9,974,427		3.33

Stock-based compensation expense for the three and six months ended June 30, 2018, was $6.9 million and $10.2 million, respectively, and was primarily recorded in general and administrative ("G&A") expenses (three and six months ended June 30, 2017 - $2.0 million and $3.2 million, respectively).

At June 30, 2018, there was $23.0 million (December 31, 2017 - $13.7 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.

Net Income per Share

Basic net income per share is calculated by dividing net income by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income per share is similarly calculated except that the common shares outstanding for the period is increased using the treasury stock method to reflect the potential dilution that

could occur if outstanding stock awards were vested at the end of the applicable period plus potentially issuable shares on conversion of the convertible notes. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

Weighted Average Shares Outstanding



	Three Months Ended June 30,			Six Months Ended June 30,
	2018		2017	2018		2017
Weighted average number of common and exchangeable shares outstanding	391,054,204		398,585,290	391,173,460		398,795,023
Shares issuable pursuant to stock options	4,894,633		—	2,420,509		625,631
Shares assumed to be purchased from proceeds of stock options	(4,308,138	)	—	(2,166,348	)	(604,563	)
Shares issuable pursuant to convertible notes	35,814,393		—	35,814,393		—
Weighted average number of diluted common and exchangeable shares outstanding	427,455,092		398,585,290	427,242,014		398,816,091

For the three months ended June 30, 2018, 5,240,018 options, on a weighted average basis, (three months ended June 30, 2017 - 10,634,157 options) were excluded from the diluted income (loss) per share calculation as the options were anti-dilutive. For the six months ended June 30, 2018, 7,385,714 options, on a weighted average basis, (six months ended June 30, 2017 - 9,616,800 options) were excluded from the diluted income per share calculation as the options were anti-dilutive. Shares issuable upon conversion of the 5.00% Convertible Notes due 2021 ("Convertible Notes") were dilutive and included in the diluted income per share calculation. For the three and six months ended June 30, 2018, the numerator used in the computation of diluted earnings per share included net income for the period adjusted for interest on convertible debentures and amortization of debt issuance costs of $1.7 million and $3.4 million, respectively.

7. Revenue

Most of the Company's 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 Vasconia crude, quality and transportation discounts each month. For the three and six months ended June 30, 2018, 100% (three and six months ended June 30, 2017 - 100%) of the Company's revenue resulted from oil sales. During the three and six months ended June 30, 2018, quality and transportation discounts were 14% and 15%, respectively, of the ICE Brent price (three and six months ended June 30, 2017 - 21% and 22%, respectively). During the three and six months ended June 30, 2018, the Company's production was sold primarily to three major customers in Colombia (three and six months ended June 30, 2017 - four).

As at June 30, 2018, accounts receivable included $4.8 million of accrued sales revenue which related to June 2018 production (December 31, 2017 - $11.1 million which related to December 31, 2017 production).

8. Taxes

The Company's effective tax rate was 58% in the six months ended June 30, 2018, compared with 84% in the comparative period in 2017. Current income tax expense was higher in the six months ended June 30, 2018, compared with the corresponding period in 2017, primarily as a result of higher taxable income in Colombia. The deferred income tax expense of $36.7 million for the six months ended June 30, 2018, was primarily due to excess tax depreciation compared with accounting depreciation in Colombia.

For the six months ended June 30, 2018, the difference between the effective tax rate of 58% and the 21% U.S. statutory rate was primarily due to an increase to the impact of foreign taxes, valuation allowance, stock-based compensation, foreign currency translation and non-deductible third party royalty in Colombia.

For the comparative period in 2017, the effective tax rate differed from the U.S. statutory rate of 35% primarily due to an increase in the valuation allowance, which was largely attributable to losses incurred in the United States, Brazil and Colombia, as well as the impact of a non-deductible third-party royalty in Colombia, foreign and local taxes, and stock-based compensation. These items were partially offset by foreign currency translation adjustments and other permanent differences.

9. Contingencies

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 $52.8 million as at June 30, 2018. At this time no amount has been accrued in the interim unaudited condensed consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

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

Letters of credit and other credit support

At June 30, 2018, the Company had provided letters of credit and other credit support totaling $69.8 million (December 31, 2017 - $76.0 million) as security relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.

10. Financial Instruments and Fair Value Measurement

Financial Instruments

At June 30, 2018, the Company’s financial instruments recognized in the balance sheet consisted of: cash and cash equivalents; restricted cash and cash equivalents; accounts receivable; investments; derivatives, accounts payable and accrued liabilities, long-term debt and equity compensation award liability.

Fair Value Measurement

The fair value of certain investments, derivatives and equity compensation awards (PSU and DSU) liabilities are 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") (formerly Sterling Resources Ltd.) was estimated using quoted prices at June 30, 2018 and the foreign exchange rate at that time. 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 costs 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 factors. The fair value of the DSU liabilities was estimated based on quoted market prices in an active market.

The fair value of the Company's investment in PetroTal, derivatives and PSU and DSU liabilities at June 30, 2018, and December 31, 2017, was as follows:



(Thousands of U.S. Dollars)	As at June 30, 2018		As at December 31, 2017
Investment in PetroTal shares - current and long-term	$	47,956	$	44,202
Foreign currency derivative asset	930		302
	$	48,886	$	44,504

Commodity price derivative liability	$	27,157	$	21,151
Equity compensation award liability - current and long-term	21,077		11,430
	$	48,234	$	32,581

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



	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017			2018			2017
Commodity price derivative loss (gain)	$	14,461		$	(1,545	)	$	19,455		$	(6,247	)
Foreign currency derivatives loss (gain)	1,945			98			(2,024		)	(639		)
Investment gain	(11,638		)	—			(5,717		)	—
Financial instruments loss (gain)	$	4,768		$	(1,447	)	$	11,714		$	(6,886	)

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

Financial instruments not recorded at fair value include the Senior Notes and the Convertible Notes. At June 30, 2018, the carrying amounts of the Senior Notes and the Convertible Notes were $288.6 million and $111.5 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $282.0 million and $143.8 million, respectively. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

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

At June 30, 2018, the fair value of the current portion of the investment and DSU liability was determined using Level 1 inputs, the fair value of derivatives and PSUs was determined using Level 2 inputs and the fair value of the long-term portion of the investment restricted by escrow conditions was determined using Level 3 inputs. The table below presents the fair value of the long-term portion of the investment:



	Six Months Ended			Year Ended
(Thousands of U.S. Dollars)	June 30, 2018			December 31, 2017
Opening balance, investment - long-term	$	19,147		$	—
Acquisition	—			19,091
Transfer from long-term (Level 3) to current (Level 1)	(4,787		)	—
Unrealized valuation gain	2,528			56
Unrealized foreign exchange loss	(1,586		)	—
Closing balance, investment - long-term	$	15,302		$	19,147

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

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

Commodity Price Derivatives

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

At June 30, 2018, the Company had outstanding commodity price derivative positions as follows:



Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

The Company does not have any outstanding commodity price derivative positions relating to 2019.

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 June 30, 2018, 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	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: July 1, 2018 to December 31, 2018	87,000	29,685	COP	3,000	3,107

⁽¹⁾At June 30, 2018 foreign exchange rate.

11. 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 June 30,				As at December 31,
	2018		2017		2017		2016
Cash and cash equivalents	$	125,807	$	53,310	$	12,326	$	25,175
Restricted cash and cash equivalents - current	2,836		5,844		11,787		8,322
Restricted cash and cash equivalents - long-term (included in other long-term assets)	2,282		9,897		2,565		9,770
	$	130,925	$	69,051	$	26,678	$	43,267

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



	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017
Accounts receivable and other long-term assets	$	(11,723	)	$	11,024
Derivatives	3,431			—
Inventory	(3,054		)	(47		)
Prepaids	(301		)	2,190
Accounts payable and accrued and other long-term liabilities	971			(6,179		)
Taxes receivable and payable	(27,318		)	(35,100		)
Net changes in assets and liabilities from operating activities	$	(37,994	)	$	(28,112	)

The following table provides additional supplemental cash flow disclosures:



	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	62,009	$	56,044

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 2017 Annual Report on Form 10-K, filed with the SEC on February 27, 2018. 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 2017 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the second quarter of 2018⁽¹⁾


•	Achieved a new company milestone: record Colombia working interest production before royalties of 35,400 BOEPD, 18% higher compared with 30,098 BOEPD in the second quarter of 2017. Production increased largely because of production from development activities in the Acordionero Field.


•	The quarter's Colombia production was also up 57% from second quarter 2015 when the strategy to refocus Gran Tierra on Colombia began, an annual growth rate of 16%


•	Since acquiring the Acordionero field in the Middle Magdalena Valley ("MMV") in August 2016, we have increased production 274% to a record high average rate during the quarter of 17,710 bopd (14,076 bopd NAR). From the acquisition date of August 23, 2016, until June 30, 2018, the MMV assets have generated $327 million in oil and natural gas sales


•	Production NAR was 28,198 BOEPD, 12% higher than the second quarter of 2017.


•	Continued significant exposure to oil price strength with oil representing 100% of our production


•	Oil and natural gas sales volumes were 27,902 BOEPD, 11% higher than the second quarter of 2017. The quarter's increase in oil and gas sales volumes was driven by the production increase (5,302 bopd) , partially offset by higher royalties (2,383 bopd) due to higher oil prices and a change in inventories (149 bopd).


•	Net income was $20.3 million compared with net loss of $6.8 million in the second quarter of 2017. Net loss in the comparative period included the loss on sale of Brazil business unit.


•	Funds flow from operations⁽²⁾ increased by 86% to $94.5 million compared with the second quarter of 2017, while the Brent price increased only 47% from the second quarter of 2017.


•	Active quarter with capital expenditures of $84.4 million. Funds flow from operations exceeded capital expenditures by $10.2 million.


•	Oil and gas sales per BOE were $64.37, 60% higher than the second quarter of 2017.


•	Operating netback⁽²⁾ per BOE was $47.99, 85% higher compared with the second quarter of 2017.


•	Operating expenses per BOE were $13.81, 21% higher compared with the second quarter of 2017 as a result of payments triggered by renegotiating our field operating agreements, power generation costs, equipment rental and accelerated maintenance costs, mainly in the Acordionero field, in the quarter.


•	Quality and transportation discount was $10.53 per BOE compared with $10.74 per BOE in the second quarter of 2017; this $0.21 per BOE reduction resulted from optimization of transportation routes and narrowing of differentials


•	Transportation expenses per BOE were $2.57, 7% lower compared with the second quarter of 2017. The decrease was due to the increased use of alternative transportation routes, which had lower costs per BOE.


•	General and administrative ("G&A") expenses before stock-based compensation per BOE decreased by 18% to $2.60 per BOE compared with the second quarter of 2017.


•	Exited the quarter with $125.8 million of cash and cash equivalents.

⁽¹⁾Except for net income, funds flow from operations and G&A expenses, all numbers and comparisons above are based on Colombia only, excluding Brazil which was sold in 2017.

⁽²⁾Funds flow from operations and operating netback are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to the non-GAAP measures disclosure below for a definition and reconciliation of these measures.



(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended June 30,								Three Months Ended March 31,			Six Months Ended June 30,
	2018			2017			% Change		2018			2018			2017			% Change
Average Daily Volumes (BOEPD)
Consolidated
Working Interest Production Before Royalties	35,400			31,437			13		35,075			35,239			30,663			15
Royalties	(7,202		)	(5,014		)	44		(6,886		)	(7,045		)	(5,051		)	39
Production NAR	28,198			26,423			7		28,189			28,194			25,612			10
Increase in Inventory	(296		)	(140		)	111		(986		)	(639		)	(61		)	948
Sales⁽¹⁾	27,902			26,283			6		27,203			27,555			25,551			8

Colombia
Working Interest Production Before Royalties	35,400			30,098			18		35,075			35,239			29,294			20
Royalties	(7,202		)	(4,819		)	49		(6,886		)	(7,045		)	(4,843		)	45
Production NAR	28,198			25,279			12		28,189			28,194			24,451			15
Increase in Inventory	(296		)	(147		)	101		(986		)	(639		)	(70		)	813
Sales⁽¹⁾	27,902			25,132			11		27,203			27,555			24,381			13

Net Income (Loss)	$	20,300		$	(6,807	)	398		$	17,861		$	38,161		$	5,964		540

Operating Netback
Oil and Natural Gas Sales	$	163,446		$	96,128		70		$	138,228		$	301,674		$	190,787		58
Operating Expenses	(35,059		)	(27,208		)	29		(26,265		)	(61,324		)	(51,145		)	20
Transportation Expenses	(6,522		)	(6,492		)	—		(6,997		)	(13,519		)	(13,434		)	1
Operating Netback⁽²⁾	$	121,865		$	62,428		95		$	104,966		$	226,831		$	126,208		80

G&A Expenses Before Stock-Based Compensation	$	6,604		$	7,610		(13	)	$	7,982		$	14,586		$	15,173		(4	)
G&A Stock-Based Compensation	6,609			1,903			247		3,178			9,787			3,052			221
General and Administrative ("G&A") Expenses, Including Stock-Based Compensation	$	13,213		$	9,513		39		$	11,160		$	24,373		$	18,225		34

EBITDA⁽²⁾	$	102,278		$	41,634		146		$	88,588		$	190,866		$	103,172		85

Funds Flow From Operations⁽²⁾	$	94,549		$	50,920		86		$	74,748		$	169,297		$	95,946		76

Capital Expenditures	$	84,394		$	57,865		46		$	72,694		$	157,088		$	104,025		51



	As at
(Thousands of U.S. Dollars)	June 30, 2018		December 31, 2017		% Change
Cash and Cash Equivalents	$	125,807	$	12,326	921

Revolving Credit Facility	$	—	$	148,000	(100	)

Senior Notes	$	300,000	$	—	—

Convertible Notes	$	115,000	$	115,000	—

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

⁽²⁾Non-GAAP measures

Operating netback, EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net income or loss 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 and transportation expenses. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil and natural gas sales to operating netback is provided in the table above.

EBITDA, as presented, is defined as net income or loss adjusted for depletion, depreciation and accretion ("DD&A") expenses, interest expense and income tax expense. Management uses this supplemental measure to analyze performance and income or loss 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 useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net loss to EBITDA is as follows:



	Three Months Ended June 30,					Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017			2018		2018		2017
Net income (loss)	$	20,300	$	(6,807	)	$	17,861	$	38,161	$	5,964
Adjustments to reconcile net income (loss) to EBITDA
DD&A expenses	46,607		31,813			39,461		86,068		58,689
Interest expense	7,375		3,331			5,495		12,870		6,426
Income tax expense	27,996		13,297			25,771		53,767		32,093
EBITDA (non-GAAP)	102,278		41,634			88,588		190,866		103,172

Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred tax expense, stock-based compensation expense, amortization of debt issuance costs, cash settlement of RSUs, unrealized foreign exchange gains and losses, financial instruments gains or losses, cash settlement of financial instruments and loss on sale. Management uses this financial measure to analyze performance and income or loss 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 or loss to funds flow from operations is as follows:



	Three Months Ended June 30,						Three Months Ended March 31,			Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017			2018			2018			2017
Net income (loss)	$	20,300		$	(6,807	)	$	17,861		38,161			$	5,964
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses	46,607			31,813			39,461			86,068			58,689
Deferred tax expense	23,169			11,525			13,482			36,651			22,904
Stock-based compensation expense	6,893			1,980			3,309			10,202			3,183
Amortization of debt issuance costs	843			620			670			1,513			1,225
Cash settlement of RSUs	(240		)	(183		)	(120		)	(360		)	(501		)
Unrealized foreign exchange loss (gain)	1,583			3,895			(1,044		)	539			1,076
Financial instruments loss (gain)	4,768			(1,447		)	6,946			11,714			(6,886		)
Cash settlement of financial instruments	(9,666		)	448			(5,817		)	(15,483		)	1,216
Loss on sale	292			9,076			—			292			9,076
Funds flow from operations (non-GAAP)	$	94,549		$	50,920		$	74,748		$	169,297		$	95,946

Additional Operational Results



	Three Months Ended June 30,								Three Months Ended March 31,			Six Months Ended June 30,
	2018			2017			% Change		2018			2018			2017			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	163,446		$	96,128		70		$	138,228		$	301,674		$	190,787		58
Operating expenses	35,059			27,208			29		26,265			61,324			51,145			20
Transportation expenses	6,522			6,492			—		6,997			13,519			13,434			1
Operating netback⁽¹⁾	121,865			62,428			95		104,966			226,831			126,208			80

DD&A expenses	46,607			31,813			47		39,461			86,068			58,689			47
G&A expenses before stock-based compensation	6,604			7,610			(13	)	7,982			14,586			15,173			(4	)
G&A stock-based compensation expense	6,609			1,903			247		3,178			9,787			3,052			221
Equity tax	—			—			—		—			—			1,224			(100	)
Foreign exchange loss (gain)	1,924			3,897			(51	)	(942		)	982			2,050			(52	)
Financial instruments loss (gain)	4,768			(1,447		)	430		6,946			11,714			(6,886		)	270
Interest expense	7,375			3,331			121		5,495			12,870			6,426			100
	73,887			47,107			57		62,120			136,007			79,728			71

Loss on sale	(292		)	(9,076		)	(97	)	—			(292		)	(9,076		)	(97	)
Interest income	610			245			149		786			1,396			653			114

Income before income taxes	48,296			6,490			644		43,632			91,928			38,057			142

Current income tax expense	4,827			1,772			172		12,289			17,116			9,189			86
Deferred income tax expense	23,169			11,525			101		13,482			36,651			22,904			60
	27,996			13,297			111		25,771			53,767			32,093			68
Net income (loss)	$	20,300		$	(6,807	)	398		$	17,861		$	38,161		$	5,964		540




Sales Volumes (NAR)
Total sales volumes, BOEPD	27,902			26,283			6		27,203			27,555			25,551			8

Average Prices
Oil and NGL's per bbl	$	64.50		$	40.44		59		$	56.63		$	60.64		$	41.65		46
Natural gas per Mcf	$	2.26		$	2.52		(10	)	$	2.91		$	2.67		$	1.91		40

Brent Price per bbl	$	74.90		$	50.92		47		$	67.18		$	71.04		$	52.79		35

Consolidated Results of Operations per BOE Sales Volumes NAR
Oil and natural gas sales	$	64.37		$	40.19		60		$	56.46		$	60.49		$	41.25		47
Operating expenses	13.81			11.38			21		10.73			12.30			11.06			11
Transportation expenses	2.57			2.71			(5	)	2.86			2.71			2.90			(7	)
Operating netback⁽¹⁾	47.99			26.10			84		42.87			45.48			27.29			67

DD&A expenses	18.36			13.30			38		16.12			17.26			12.69			36
G&A expenses before stock-based compensation	2.60			3.18			(18	)	3.26			2.92			3.28			(11	)
G&A stock-based compensation expense	2.60			0.80			225		1.30			1.96			0.66			197
Equity tax	—			—			—		—			—			0.26			(100	)
Foreign exchange loss (gain)	0.76			1.63			(53	)	(0.38		)	0.20			0.44			(55	)
Financial instruments loss (gain)	1.88			(0.60		)	413		2.84			2.35			(1.49		)	258
Interest expense	2.90			1.39			109		2.24			2.58			1.39			86
	29.10			19.70			48		25.38			27.27			17.23			58

Loss on sale	(0.12		)	(3.79		)	(97	)	—			(0.06		)	(1.96		)	(97	)
Interest income	0.24			0.10			140		0.32			0.28			0.14			100

Income before income taxes	19.01			2.71			601		17.81			18.43			8.24			124
Current income tax expense	1.90			0.74			157		5.02			3.43			1.99			72
Deferred income tax expense	9.12			4.82			89		5.51			7.35			4.95			48
	11.02			5.56			98		10.53			10.78			6.94			55
Net income (loss)	$	7.99		$	(2.85	)	380		$	7.28		$	7.65		$	1.30		488

⁽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 and reconciliation of this measure.

Oil and Gas Production and Sales Volumes, BOEPD



	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
Average Daily Volumes (BOEPD)	Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	35,400		30,098		1,339		31,437
Royalties	(7,202	)	(4,819	)	(195	)	(5,014	)
Production NAR	28,198		25,279		1,144		26,423
(Increase) Decrease in Inventory	(296	)	(147	)	7		(140	)
Sales	27,902		25,132		1,151		26,283

Royalties, % of Working Interest Production Before Royalties	20	%	16	%	15	%	16	%

	Six Months Ended June 30, 2018		Six Months Ended June 30, 2017
Average Daily Volumes (BOEPD)	Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	35,239		29,294		1,369		30,663
Royalties	(7,045	)	(4,843	)	(208	)	(5,051	)
Production NAR	28,194		24,451		1,161		25,612
(Increase) Decrease in Inventory	(639	)	(70	)	9		(61	)
Sales	27,555		24,381		1,170		25,551

Royalties, % of Working Interest Production Before Royalties	20	%	17	%	15	%	16	%

Oil and gas production NAR for the three and six months ended June 30, 2018 increased by 7% to 28,198 and by 10% to 28,194 BOEPD compared with 26,423 and 25,612 BOEPD, respectively, in the corresponding periods of 2017.

Colombian oil and gas production NAR for the three and six months ended June 30, 2018 increased by 12% and 15%, respectively, compared with the corresponding periods of 2017. The increase in production was a result of successful drilling and a workover campaign in the Acordionero and Costayaco Fields and the Vonu-1 exploration well. Working interest production before royalties from the Acordionero Field averaged 17,710 bopd before royalties (14,076 bopd NAR) during the three months ended June 30, 2018 compared with 8,362 bopd in the corresponding period of 2017, a 112% increase. Acordionero Field production increased 959 bopd before royalties from the three months ended March 31, 2018. During the second quarter of 2018, four wells were brought on production. Production was negatively impacted by two Electronic Submersible Pumps ("ESPs") failures in Acordionero and one ESP failure in Costayaco.

Royalties as a percentage of production for the three and six months ended June 30, 2018 increased compared with the corresponding periods of 2017 commensurate with the increase in oil prices due to price sensitive royalties payable in Colombia, higher API in the Acordionero Field and this field reaching the threshold for the High Price Royalties.

Operating Netbacks



	Three Months Ended June 30, 2018			Three Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Total			Colombia			Brazil			Total
Oil and Natural Gas Sales	$	163,446		$	91,905		$	4,223		$	96,128
Transportation Expenses	(6,522		)	(6,319		)	(173		)	(6,492		)
	156,924			85,586			4,050			89,636
Operating Expenses	(35,059		)	(26,192		)	(1,016		)	(27,208		)
Operating Netback⁽¹⁾	$	121,865		$	59,394		$	3,034		$	62,428

U.S. Dollars Per BOE Sales Volumes NAR
Brent	$	74.90		$	50.92		$	50.92		$	50.92
Vasconia, Quality and Transportation Discounts	(10.53		)	(10.74		)	(10.62		)	(10.73		)
Average Realized Price	64.37			40.18			40.30			40.19
Transportation Expenses	(2.57		)	(2.76		)	(1.65		)	(2.71		)
Average Realized Price Net of Transportation Expenses	61.80			37.42			38.65			37.48
Operating Expenses	(13.81		)	(11.45		)	(9.69		)	(11.38		)
Operating Netback⁽¹⁾	$	47.99		$	25.97		$	28.96		$	26.10

	Six Months Ended June 30, 2018			Six Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Total			Colombia			Brazil			Total
Oil and Natural Gas Sales	$	301,674		$	182,369		$	8,418		$	190,787
Transportation Expenses	(13,519		)	(13,084		)	(350		)	(13,434		)
	288,155			169,285			8,068			177,353
Operating Expenses	(61,324		)	(49,348		)	(1,797		)	(51,145		)
Operating Netback⁽¹⁾	$	226,831		$	119,937		$	6,271		$	126,208

U.S. Dollars Per BOE Sales Volumes NAR
Brent	$	71.04		$	52.79		$	52.79		$	52.79
Vasconia, Quality and Transportation Discounts	(10.55		)	(11.46		)	(13.03		)	(11.54		)
Average Realized Price	60.49			41.33			39.76			41.25
Transportation Expenses	(2.71		)	(2.96		)	(1.65		)	(2.90		)
Average Realized Price Net of Transportation Expenses	57.78			38.37			38.11			38.35
Operating Expenses	(12.30		)	(11.18		)	(8.49		)	(11.06		)
Operating Netback⁽¹⁾	$	45.48		$	27.19		$	29.62		$	27.29

Oil and gas sales for the three and six months ended June 30, 2018 increased by 70% to $163.4 million and 58% to $301.7 million, respectively, compared with the corresponding periods of 2017. Compared with the prior quarter, oil and gas sales increased by 18%. The increases were due to increased sales volumes and realized oil prices. The following table shows the effect of changes in realized prices and sales volumes on our oil and gas sales for the three and six months ended June 30, 2018 compared with the prior quarter and the corresponding periods in 2017:



	Second Quarter 2018 Compared with First Quarter 2018		Second Quarter 2018 Compared with Second Quarter 2017		Six Months Ended, June 30, 2018 Compared with Six Months Ended June 30, 2017
Oil and natural gas sales for the comparative period	$	138,228	$	96,128	$	190,787
Realized sales price increase effect	20,096		61,401		95,920
Sales volume increase effect	5,122		5,917		14,967
Oil and natural gas sales for period ended June 30, 2018	$	163,446	$	163,446	$	301,674

Average realized prices for the three and six months ended June 30, 2018 increased by 60% and 47%, respectively, compared with the corresponding periods of 2017. Compared with the prior quarter, average realized prices increased by 14%. The increases were commensurate with increases in benchmark oil prices and lower quality and transportation discounts. Average Brent oil prices for the three and six months ended June 30, 2018 increased by 47% and 35%, respectively, compared with the corresponding periods of 2017 and increased by 11% compared with the prior quarter.

We have options to sell our oil through multiple pipelines and trucking routes. Each transportation route has varying effects on realized sales prices and transportation expenses. We focus on maximizing operating netback. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for the three and six months ended June 30, 2018 and 2017 and the prior quarter:



	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
	2018		2017		2018		2018		2017
Volume transported through pipeline	9	%	20	%	9	%	9	%	22	%
Volume sold at wellhead	41	%	52	%	52	%	42	%	52	%
Volume not sold at wellhead, trucking	50	%	28	%	39	%	49	%	26	%
	100	%	100	%	100	%	100	%	100	%

Volumes transported not sold at the wellhead receive higher realized prices, but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized prices, offset by lower transportation expenses.

Total Company transportation expenses for the three and six months ended June 30, 2018 of $6.5 million and $13.5 million, respectively, were comparable with the corresponding periods of 2017. On a per BOE basis, transportation expenses for the three and six months ended June 30, 2018 decreased by 5% to $2.57, and by 7% to $2.71, from $2.71 and $2.90, respectively, compared with the corresponding periods of 2017. The decrease was primarily due to the use of alternative transportation routes, which had lower costs per BOE.

Colombian transportation expenses for the three and six months ended June 30, 2018 on a per BOE basis decreased by 7% and 8% to $2.57 and $2.71 per BOE, from $2.76 and $2.96, respectively in the corresponding periods of 2017. The decrease in Colombian transportation expenses per BOE was due to renegotiation of certain sales contracts, which had lower transportation costs compared to contracts used in 2017.

Transportation expenses for the three months ended June 30, 2018 decreased 7% compared with $7.0 million in the prior quarter. On a per BOE basis, transportation expenses decreased by 10% to $2.57 from $2.86 in the prior quarter. The decrease was primarily due to the use of alternative transportation routes, which had lower costs per BOE.

In addition to lower transportation expenses, we also achieved decreases in quality and transportation discounts. The following table shows the variance in our average realized prices net of transportation expenses in Colombia for the three and six months ended June 30, 2018 compared with the prior quarter and the corresponding periods in 2017:



U.S. Dollars Per BOE Sales Volumes NAR	Second Quarter 2018 Compared with First Quarter 2018		Second Quarter 2018 Compared with Second Quarter 2017		Six Months Ended, June 30, 2018 Compared with Six Months Ended June 30, 2017
Average realized price net of transportation expenses for the comparative period	$	53.60	$	37.42	$	38.37
Increase in benchmark prices	7.72		$	23.98	18.25
Decrease in quality and transportation discounts	0.19		0.21		0.91
Decrease in transportation expenses	0.29		0.19		0.25
Average realized price net of transportation expenses for the period ended June 30, 2018	$	61.80	$	61.80	$	57.78

Total Company operating expenses for the three and six months ended June 30, 2018 increased by 29% to $35.1 million, and by 20% to $61.3 million, respectively, compared with total Company operating expenses in the corresponding periods of 2017.

Colombian operating expenses for the three and six months ended June 30, 2018 on a per BOE basis increased by $2.36 and $1.12, respectively, compared with the corresponding periods of 2017. Workover expenses increased by $0.11 and decreased by $0.27, respectively, over the same periods. Excluding workover expenses, Colombia operating expenses increased by $2.25 and $1.39, respectively, primarily as a result of payments triggered by renegotiating our field operating agreements, power generation costs, equipment rental and accelerated maintenance costs mainly in the Acordionero field during the second quarter of 2018.

Operating expenses for the three months ended June 30, 2018 increased by 33% compared with the prior quarter. On a per BOE basis, operating expenses increased by $3.08. Workover expenses increased by $1.45. Excluding workover expenses, operating expenses increased by $1.63 compared with the prior quarter as a result of higher operating activities during the second quarter of 2018 mentioned in the paragraph above.

DD&A Expenses



	Three Months Ended June 30, 2018				Three Months Ended June 30, 2017
	DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE		DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE
Colombia	$	46,065	$	18.14	$	30,130	$	13.17
Brazil	—		—		1,050		10.02
Peru	—		—		412		—
Corporate	542		—		221		—
	$	46,607	$	18.36	$	31,813	$	13.30

	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
	DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE		DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE
Colombia	$	84,564	$	16.96	$	55,065	$	12.48
Brazil	—		—		2,263		10.69
Peru	—		—		921		—
Corporate	1,504		—		440		—
	$	86,068	$	17.26	$	58,689	$	12.69

DD&A expenses for the three and six months ended June 30, 2018 increased to $46.6 million ($18.36 per BOE) and $86.1 million ($17.26 per BOE), respectively, from $31.8 million ($13.30 per BOE) and $58.7 million ($12.69 per BOE), respectively, in the corresponding periods in 2017. On a per BOE basis, the increase was due to higher costs in the depletable base, partially offset by increased proved reserves. On a per BOE basis, DD&A expenses increased by 14% from $16.12 per BOE in the prior quarter primarily due to higher costs in the depletable base.

G&A Expenses



	Three Months Ended June 30,						Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017		% Change		2018		2018		2017		% Change
G&A Expenses Before Stock-Based Compensation	$	6,604	$	7,610	(13	)	$	7,982	$	14,586	$	15,173	(4	)
G&A Stock-Based Compensation	6,609		1,903		247		3,178		9,787		3,052		221
G&A Expenses, Including Stock-Based Compensation	$	13,213	$	9,513	39		$	11,160	$	24,373	$	18,225	34

U.S. Dollars Per BOE Sales Volumes NAR
G&A Expenses Before Stock-Based Compensation	$	2.60	$	3.18	(18	)	$	3.26	$	2.92	$	3.28	(11	)
G&A Stock-Based Compensation	2.60		0.80		225		1.30		1.96		0.66		197
G&A Expenses, Including Stock-Based Compensation	$	5.20	$	3.98	31		$	4.56	$	4.88	$	3.94	24

For the three and six months ended June 30, 2018, G&A expenses before stock-based compensation decreased by 13% and 4%, respectively, from the corresponding periods of 2017. The decrease was primarily the result of higher overhead recoveries, partially offset by increase in Colombia and Corporate G&A expenses commensurate with our growth. On a per BOE basis, G&A expenses before stock-based compensation decreased 18% and 11%, respectively, from the corresponding periods of 2017.

After stock-based compensation, G&A expenses for the three and six months ended June 30, 2018 increased by 39% to $13.2 million and by 34% to $24.4 million, respectively, compared with the corresponding periods in 2017 mainly due to higher G&A Stock-Based Compensation resulting from a higher share price at June 30, 2018. G&A expenses for the three months ended June 30, 2018 increased by 18% compared with the prior quarter for the same reason.

Foreign Exchange Losses

For the three and six months ended June 30, 2018 we had foreign exchange losses of $1.9 million and $1.0 million, respectively, compared with $3.9 million and $2.1 million, respectively, in the corresponding periods of 2017. Deferred taxes are considered a monetary liability 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 gains and losses. Due to the long-term nature of deferred tax liabilities, the related foreign exchange losses are not expected to be realized in the near-term.

The following table presents the change in the U.S. dollar against the Colombian peso for the three and six months ended June 30, 2018, and 2017:



	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Change in the U.S. dollar against the Colombian peso	strengthened by	strengthened by	weakened by	strengthened by
Change in the U.S. dollar against the Colombian peso	5%	6%	2%	1%

Financial Instrument Gains and Losses

The following table presents the nature of our financial instruments gains and losses for the three and six months ended June 30, 2018, and 2017:



	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017			2018			2017
Commodity price derivative loss (gain)	$	14,461		$	(1,545	)	$	19,455		$	(6,247	)
Foreign currency derivatives loss (gain)	1,945			98			(2,024		)	(639		)
Investment gain	(11,638		)	—			(5,717		)	—
	$	4,768		$	(1,447	)	$	11,714		$	(6,886	)

Income Tax Expense and Recovery



	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017		2018			2017
Income before income tax	$	48,296	$	6,490	$	91,928		$	38,057

Current income tax expense	$	4,827	$	1,772	$	17,116		$	9,189
Deferred income tax expense	23,169		11,525		36,651			22,904
Total income tax expense	$	27,996	$	13,297	$	53,767		$	32,093

Effective tax rate					58		%	84		%

Current income tax expense was higher in the three and six months ended June 30, 2018 compared with the corresponding periods of 2017 as a result of higher taxable income in Colombia. The deferred income tax expense for the three and six months ended

June 30, 2018 of $23.2 million and $36.7 million, respectively, was primarily due to excess tax depreciation as compared with accounting depreciation in Colombia.

Current income tax expense decreased to $4.8 million compared with $12.3 million in the prior quarter primarily as a result of accelerated tax write-off related to current period drilling activities.

For the six months ended June 30, 2017, the difference between the effective tax rate of 84% and the 35% U.S. statutory rate was primarily due to an increase in the impact of foreign taxes, other permanent differences, valuation allowance largely attributable to losses incurred in the United States and Colombia, as well as the impact of a non-deductible third-party royalty in Colombia, stock-based compensation and other local taxes.

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



(Thousands of U.S. Dollars)	Second Quarter 2018 Compared with First Quarter 2018			% change		Second Quarter 2018 Compared with Second Quarter 2017			% change		Six Months Ended, June 30, 2018 Compared with Six Months Ended June 30, 2017			% change
Net income (loss) for the comparative period	$	17,861				$	(6,807	)			$	5,964
Increase (decrease) due to:
Prices	20,096					61,401					95,920
Sales volumes	5,122					5,917					14,967
Expenses:
Operating	(8,794		)			(7,851		)			(10,179		)
Transportation	475					(30		)			(85		)
Cash G&A and RSU settlements, excluding stock-based compensation expense	1,411					1,156					1,012
Interest, net of amortization of debt issuance costs	(1,707		)			(3,821		)			(6,156		)
Realized foreign exchange	(240		)			(338		)			531
Settlement of financial instruments	(3,849		)			(10,114		)			(16,699		)
Current taxes	7,462					(3,055		)			(7,927		)
Equity tax	—					—					1,224
Other	(175		)			364					743
Net change in funds flow from operations⁽¹⁾ from comparative period	19,801					43,629					73,351
Expenses:
Depletion, depreciation and accretion	(7,146		)			(14,794		)			(27,379		)
Deferred tax	(9,687		)			(11,644		)			(13,747		)
Amortization of debt issuance costs	(173		)			(223		)			(288		)
Stock-based compensation, net of RSU settlement	(3,464		)			(4,856		)			(7,160		)
Financial instruments gain or loss, net of financial instruments settlements	6,027					3,899					(1,901		)
Unrealized foreign exchange	(2,627		)			2,312					537
Loss on sale	(292		)			8,784					8,784
Net change in net income or loss	2,439					27,107					32,197
Net income for the current period	$	20,300		14	%	$	20,300		398	%	$	38,161		540	%

⁽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.

2018 Capital Program

Colombia remains our focus and represents 100% of the 2018 capital program. We have expanded the 2018 development capital program by an additional $15 to $30 million for;


•	Ayombero appraisal drilling of 3 wells based on the success of the Ayombero-1 well;


•	Costayaco development drilling in legacy reservoirs and 1 additional water injection well; and


•	2 Acordionero development wells accelerated from 2019 into fourth quarter 2018.

We expect the following ranges for our revised 2018 capital budget:



	Number of Wells (Gross)	Number of Wells (Net)	2018 Capital Budget ($ million)
Colombia
Development	22-24	21-22	$130-135
Exploration	8-11	7-10	80-90
Facilities	—	—	75-80
Seismic and Studies	—	—	20
	30-35	28-32	$305-325

Based on the midpoint of the guidance, the capital budget is forecasted to be approximately 68% directed to development and 32% to exploration. Between 35% and 40% of the revised 2018 development capital program is expected to be directed to facilities, with approximately 75% of this investment expected to be dedicated to the acceleration of the ongoing facilities expansion at the Acordionero Field. We expect our revised 2018 capital program to be fully funded by cash flows from operations.

Capital expenditures during the three months ended June 30, 2018, were $84.4 million:



(Thousands of U.S. Dollars)
Colombia:
Exploration	$	18,301
Development:
Facilities	16,957
Drilling and Completions	41,696
Other	6,803
	83,757
Corporate	637
	$	84,394

During the three months ended June 30, 2018, we drilled the following wells in Colombia:



	Number of wells (Gross)	Number of wells (Net)
Development	5	5.0
Exploration	1	0.5
Total Colombia	6	5.5

Five development wells were spud, consisting of two in the Midas Block (Acordionero-23-i and 24), two in the Chaza Block (Costayaco-33 and 35-i), and one in the Putumayo-7 Block (Cumplidor-2). Three of these wells are currently on production (Costayaco-33, 35-i and Cumplidor-2). Additionally, of the wells that were in-progress at March 31, 2018, three development wells (Acordionero-20, 22 and Costayaco-32) are currently producing. We also drilled the Tonga-1 exploration well in the Sinu-3 Block, which was plugged and abandoned as the well did not encounter commercial hydrocarbon quantities. This was a commitment exploration well.

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

During the three months ended June 30, 2018, we acquired additional working interests in Alea1848-A and 1947-C for total cash consideration of $3.1 million, which increased our position in these blocks to 100% and expanded our exploration opportunities in the Putumayo Basin. These acquisitions are subject to approval by the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency).

Liquidity and Capital Resources



	As at
(Thousands of U.S. Dollars)	June 30, 2018		% Change		December 31, 2017
Cash and Cash Equivalents	$	125,807	921		$	12,326

Current Restricted Cash and Cash Equivalents	$	2,836	(76	)	$	11,787

Revolving Credit Facility	$	—	(100	)	$	148,000

Senior Notes	$	300,000	—		$	—

Convertible Notes	$	115,000	—		$	115,000

We believe that our capital resources, including cash on hand, cash generated from operations and available capacity on our credit facility, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for 2018, given current oil price trends and production levels. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions.

At June 30, 2018, we had a revolving credit facility with a syndicate of lenders with a borrowing base of $300 million and we had zero drawn on this credit facility. 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 2018.

At June 30, 2018, we had $115 million aggregate principal amount of 5.00% Convertible Senior Notes due 2021 (the "Convertible Notes") and $300 million aggregate principal amount of 6.25% Senior Notes due 2025 (the "Senior Notes") outstanding. The Convertible Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on April 1 and October 1 of each year. The Convertible Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted. The Convertible Notes are convertible to Common Stock at a conversion price of approximately $3.21 per share of Common Stock at the option of the holder at any time prior to the close of business on the business day immediately preceding the maturity date. The Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

Under the terms of our credit facility and Senior Notes, we are required to maintain compliance with certain financial and operating covenants which include: limitations on our ratio of debt to net income plus interest, taxes, depreciation, depletion, amortization, exploration expenses and all non-cash charges minus all non-cash income ("EBITDAX") to a maximum of 4.0 to 1.0 (under the credit facility) and 3.5 to 1.0 (under the Senior Notes); the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0 (definitions of debt, EBITDAX and other relevant terms are per the credit agreement or the indenture governing the Senior Notes and may differ between these agreements). As at June 30, 2018, 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.

Cash and Cash Equivalents Held Outside of Canada and the United States

At June 30, 2018, 100% of our cash and cash equivalents were held by subsidiaries and partnerships outside of Canada and the United States. This cash was generally not available to fund domestic or head office operations unless funds were repatriated. At this time, we do not intend to repatriate further funds other than to pay head office charges, but if we did, we might have to accrue and pay withholding taxes in certain jurisdictions on the distribution of accumulated earnings. Undistributed earnings of foreign subsidiaries are considered to be permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.

In Colombia, we participate in a special exchange regime, and we receive revenue in U.S. dollars offshore. We may also pay invoices denominated in U.S. dollars for our Colombian business from these U.S. dollars received offshore.

Derivative Positions

At June 30, 2018, we had outstanding commodity price derivative positions as follows:



Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

At June 30, 2018, current liabilities on our balance sheet included $27.2 million in relation to the above outstanding commodity price derivative positions.

At June 30, 2018, we had the following outstanding foreign currency derivative positions:



Period and type of instrument	Amount Hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)⁽¹⁾	Reference	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: July 1, 2018 to December 31, 2018	87,000	29,685	COP	3,000	3,107

⁽¹⁾At June 30, 2018 foreign exchange rate.

At June 30, 2018, current assets on our balance sheet included $0.9 million in relation to the above outstanding foreign currency derivative positions. We do not have any outstanding commodity price derivative positions relating to 2019.

Cash Flows

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



	Six Months Ended June 30,
	2018			2017
Sources of cash and cash equivalents:
Net income	$	38,161		$	5,964
Adjustments to reconcile net income to EBITDA⁽¹⁾ and funds flow from operations⁽¹⁾
DD&A expenses	86,068			58,689
Interest expense	12,870			6,426
Income tax expense	53,767			32,093
EBITDA	190,866			103,172
Current income tax expense	(17,116		)	(9,189		)
Stock-based compensation expense	10,202			3,183
Contractual interest and other financing expenses	(11,357		)	(5,201		)
Cash settlement of RSUs	(360		)	(501		)
Unrealized foreign exchange loss	539			1,076
Financial instruments loss (gain)	11,714			(6,886		)
Cash settlement of financial instruments	(15,483		)	1,216
Loss on sale	292			9,076
Funds flow from operations	169,297			95,946
Proceeds from bank debt, net of issuance costs	4,988			98,304
Proceeds from issuance of Senior Notes, net of issuance costs	288,087			—
Proceeds from issuance of shares	845			—
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit	—			4,700
Deposit received for sale of Brazil business unit	—			34,481
	463,217			233,431

Uses of cash and cash equivalents:
Additions to property, plant and equipment	(157,088		)	(104,025		)
Additions to property, plant and equipment - property acquisitions	(3,100		)	(30,410		)
Repayment of bank debt	(153,000		)	(33,000		)
Repurchase of shares of Common Stock	(1,208		)	(10,000		)
Net changes in assets and liabilities from operating activities	(37,994		)	(28,112		)
Changes in non-cash investing working capital	(6,142		)	(627		)
Settlement of asset retirement obligations	(369		)	(298		)
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(69		)	(1,175		)
	(358,970		)	(207,647		)
Net increase in cash and cash equivalents and restricted cash and cash equivalents	$	104,247		$	25,784

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

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices, the impact of which we partially mitigate by entering into commodity derivatives. Sales volume changes and costs related to operations

and debt service also impact cash flow. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes, the impact of which we partially mitigate by entering into foreign currency derivatives.

Off-Balance Sheet Arrangements

As at June 30, 2018, we had no off-balance sheet arrangements.

Contractual Obligations

During February 2018, we issued $300 million aggregate principal amount of the Senior Notes. Refer to Note 5 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Form 10-Q, incorporated herein by reference, for further information. During the six months ended June 30, 2018, we fully repaid the balance of $153 million outstanding under our revolving credit facility, which remained undrawn at June 30, 2018.

Except as noted above, as at June 30, 2018, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as at December 31, 2017.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2017 Annual Report on Form 10-K, filed with the SEC on February 27, 2018, and have not changed materially since the filing of that document, other than as follows:

Revenue Recognition

We adopted ASC 606 Revenue from Contracts with Customers with a date of initial application of January 1, 2018 in accordance with the modified retrospective approach. Except for providing enhanced disclosures on our revenue transactions, the application of ASC 606 did not have an impact on our consolidated financial position, results of operations or cash flows.

We evaluate our arrangements with third parties and partners to determine if we act as a principal or an agent. In making this evaluation, management considers if we obtain control of the product delivered, which is indicated by us having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If we act in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by us from the transaction. When determining if we acted as a principal or as an agent in transactions, we determine if we obtain control of the product. As part of this assessment, management considered detailed criteria for revenue recognition set out in ASC 606.

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 are in U.S. dollars or are based on U.S. dollar prices. The majority of income and value added taxes and G&A expenses in Colombia are in local currency. Certain G&A expenses incurred at our head office in Canada are denominated in Canadian dollars. While we operate in South America exclusively, the majority of our acquisition expenditures have been valued and paid in U.S. dollars.

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

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

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our revolving credit facility, which bears floating rates of interest. At June 30, 2018, our outstanding revolving credit facility was nil (December 31, 2017 - $148.0 million).

Further Information

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

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(b) of the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra's disclosure controls and procedures were effective as of June 30, 2018.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2018 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 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 material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2017, 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 2017 Annual Report on Form 10-K. The risks facing our company have not changed materially from those set forth in Part I, Item 1A Risk Factors of our 2017 Annual Report on Form 10-K.

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 ⁽³⁾
April 1-30, 2018	—	—	—	18,804,820
May 1-31, 2018	4,500	2.98	4,500	18,800,320
June 1- 30, 2018	—	—	—	18,800,320
	4,500	2.98	4,500	18,800,320

⁽¹⁾ Based on settlement date.

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

⁽³⁾ On March 7, 2018, we announced that we intended to implement a share repurchase program (the “2018 Program”) through the facilities of the TSX and eligible alternative trading platforms in Canada. We received regulatory approval from the TSX to commence the 2018 Program on March 12, 2018. We are able to purchase at prevailing market prices up to 19,269,732 shares of Common Stock, representing approximately 5% of our issued and outstanding shares of Common Stock as of March 8, 2018.

Shares purchased pursuant to the 2018 Program to date have been canceled. The 2018 Program will expire on March 11, 2019, or earlier if the 5.00% share maximum is reached. The 2018 Program could be terminated by us at any time, subject to compliance with regulatory requirements. As such, there can be no assurance regarding the total number of shares that may be repurchased under the 2018 Program.

Item 6. Exhibits



Exhibit No.	Description	Reference

2.1	Plan of Conversion, dated October 31, 2016.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).

3.1	Certificate of Incorporation.	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	Bylaws of Gran Tierra Energy Inc.	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	Certificate of Retirement dated July 9, 2018	Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the SEC on July 9, 2018 (SEC File No. 001-34018).

4.1	Indenture related to the 5.00% Convertible Senior Notes due 2021, dated as of April 6, 2016, between Gran Tierra Energy Inc. and U.S. Bank National Association	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).

4.2	Form of 5.00% Convertible Senior Notes due 2021	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).

4.3	Subscription Receipt Agreement, dated July 8, 2016, by and between Gran Tierra Energy Inc. and Computershare Trust Company of Canada.	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).

4.4	Form of Registration Rights Agreement.	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).

4.5	Purchase Agreement, dated February 8, 2018, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc. and the subsidiary guarantors named therein, and Credit Suisse Securities (USA) LLC and RBC Capital Markets, LLC, as Representatives of the several initial purchasers.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on February 9, 2018 (SEC File No. 001-34018).

4.6	Indenture related to the 6.25% Senior Notes due 2025, dated as of February 15, 2018, between Gran Tierra Energy International Holdings Ltd., the Guarantors named therein and U.S. Bank National Association	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).

4.7	Form of 6.25% Senior Notes due 2025	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).

10.1	Tenth Amendment to Credit Agreement, dated as of May 25, 2018, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto	Filed herewith.

31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith.

31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith.

32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith.

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

101.LAB XBRL Taxonomy Extension Label Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

+ Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Gran Tierra undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.

SIGNATURES

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

GRAN TIERRA ENERGY INC.



Date: August 2, 2018		/s/ Gary S. Guidry
		By: Gary S. Guidry
		President and Chief Executive Officer
		(Principal Executive Officer)



Date: August 2, 2018		/s/ Ryan Ellson
		By: Ryan Ellson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)