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 March 31, 2017

or
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 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, 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 7(a)(2)(B) of the Securities 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 May 1, 2017, the following number of shares of the registrant’s capital stock were outstanding: 390,818,790 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 3,387,302 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 4,800,992 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.

 




1



Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended March 31, 2017

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

2



 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 (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”, “objective”, “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, those set out in Part II, Item 1A “Risk Factors” in our Quarterly Reports on Form 10-Q and in Part I, Item 1A “Risk Factors” in our 2016 Annual Report on Form 10-K. The information included herein is given as of the filing date of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the federal securities laws, we disclaim any obligations 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
Mbbl
thousand barrels
BOEPD
barrels of oil equivalent per day
Mcf
thousand cubic feet
bopd
barrels of oil per day
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.





3



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 March 31,
 
 
2017
 
2016
OIL AND NATURAL GAS SALES (NOTE 3)
 
$
94,659

 
$
57,403

 
 


 


EXPENSES
 
 
 
 
Operating
 
23,937

 
19,067

Transportation
 
6,942

 
12,328

Depletion, depreciation and accretion (Note 3)
 
26,593

 
36,912

Asset impairment (Notes 3 and 4)
 
283

 
56,898

General and administrative (Note 3)
 
8,712

 
7,049

Transaction
 

 
1,237

Severance
 

 
1,018

Equity tax
 
1,224

 
3,051

Foreign exchange (gain) loss
 
(1,847
)
 
785

Financial instruments (gain) loss (Note 10)
 
(5,439
)
 
845

   Interest expense (Note 5)
 
3,095

 
519

 
 
63,500

 
139,709

 
 
 
 
 
GAIN ON ACQUISITION
 


11,712

INTEREST INCOME
 
408

 
449

INCOME (LOSS) BEFORE INCOME TAXES (NOTE 3)
 
31,567

 
(70,145
)
 
 
 
 
 
INCOME TAX (EXPENSE) RECOVERY
 
 
 
 
Current
 
(7,417
)
 
(2,023
)
Deferred
 
(11,379
)
 
27,136


 
(18,796
)
 
25,113

NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
 
$
12,771

 
$
(45,032
)
 
 
 
 
 
NET INCOME (LOSS) PER SHARE - BASIC AND DILUTED
 
$
0.03

 
$
(0.15
)
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)
 
399,007,086

 
293,812,226

WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)
 
399,046,114

 
293,812,226

(See notes to the condensed consolidated financial statements)


4



Gran Tierra Energy Inc.
Condensed Consolidated Balance Sheets (Unaudited)
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
 
March 31,
 
December 31,
 
2017
 
2016
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents (Note 11)
$
26,716

 
$
25,175

Restricted cash and cash equivalents (Notes 7 and 11)
7,663

 
8,322

Accounts receivable
46,912

 
45,698

Derivatives (Note 10)
1,425

 
578

Inventory (Note 4)
7,285

 
7,766

Taxes receivable
23,284

 
26,393

Prepaid taxes (Note 2)

 
12,271

Other prepaids
4,404

 
5,482

Total Current Assets
117,689

 
131,685

 
 
 
 
Oil and Gas Properties (using the full cost method of accounting)
 

 
 

Proved
460,937

 
412,319

Unproved
620,045

 
647,774

Total Oil and Gas Properties
1,080,982

 
1,060,093

Other capital assets
6,314

 
6,516

Total Property, Plant and Equipment (Notes 3 and 4)
1,087,296

 
1,066,609

 
 
 
 
Other Long-Term Assets
 

 
 

Deferred tax assets (Note 2)
100,260

 
1,611

Prepaid taxes (Note 2)

 
41,784

Other long-term assets (Note 11)
24,467

 
23,626

Goodwill (Note 3)
102,581

 
102,581

Total Other Long-Term Assets
227,308

 
169,602

Total Assets (Note 3)
$
1,432,293

 
$
1,367,896

LIABILITIES AND SHAREHOLDERS’ EQUITY
 

 
 

Current Liabilities
 

 
 

Accounts payable and accrued liabilities
$
112,414

 
$
107,051

Derivatives (Note 10)

 
3,824

Taxes payable (Note 2)
38,210

 
38,939

Asset retirement obligation (Note 7)
1,214

 
5,215

Total Current Liabilities
151,838

 
155,029

 
 
 
 
Long-Term Liabilities
 

 
 

Long-term debt (Notes 5 and 10)
193,159

 
197,083

Deferred tax liabilities (Note 2)
36,061

 
107,230

Asset retirement obligation (Note 7)
42,960

 
38,142

Other long-term liabilities
11,332

 
11,425

Total Long-Term Liabilities
283,512

 
353,880

 
 
 
 
Contingencies (Note 9)


 


 
 
 
 
Shareholders’ Equity
 

 
 

Common Stock (Note 6) (390,815,190 and 390,807,194 shares of Common Stock and 8,191,894 and 8,199,894 exchangeable shares, par value $0.001 per share, issued and outstanding as at March 31, 2017, and December 31, 2016, respectively)
10,303

 
10,303

Additional paid in capital
1,343,365

 
1,342,656

Deficit
(356,725
)
 
(493,972
)
Total Shareholders’ Equity
996,943

 
858,987

Total Liabilities and Shareholders’ Equity
$
1,432,293

 
$
1,367,896


(See notes to the condensed consolidated financial statements)

5



Gran Tierra Energy Inc.
Condensed Consolidated Statements of Cash Flows (Unaudited)
(Thousands of U.S. Dollars)
 
Three Months Ended March 31,
 
2017
 
2016
Operating Activities
 
 
 
Net income (loss)
$
12,771

 
$
(45,032
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 

Depletion, depreciation and accretion (Note 3)
26,593

 
36,912

Asset impairment (Notes 3 and 4)
283

 
56,898

Deferred tax expense (recovery)
11,379

 
(27,136
)
Stock-based compensation (Note 6)
1,203

 
1,460

Amortization of debt issuance costs (Note 5)
605

 
140

Cash settlement of restricted share units
(318
)
 
(673
)
Unrealized foreign exchange gain
(2,819
)
 
(183
)
Financial instruments (gain) loss (Note 10)
(5,439
)
 
845

Cash settlement of financial instruments (Note 10)
768

 
44

Cash settlement of asset retirement obligation (Note 7)
(13
)
 
(104
)
Gain on acquisition

 
(11,712
)
Net change in assets and liabilities from operating activities (Note 11)
4,930

 
(647
)
Net cash provided by operating activities
49,943

 
10,812

 
 
 
 
Investing Activities
 

 
 

Additions to property, plant and equipment, excluding corporate acquisition (Note 3)
(46,160
)
 
(26,180
)
Additions to property, plant and equipment - acquisition of PetroGranada Colombia Limited

 
(19,388
)
Deposit received for Brazil Divestiture (Note 1)
3,500

 

Cash paid for business combinations, net of cash acquired

 
(40,201
)
Changes in non-cash investing working capital
(1,797
)
 
50

Net cash used in investing activities
(44,457
)
 
(85,719
)
 
 
 
 
Financing Activities
 

 
 

Proceeds from bank debt, net of issuance costs (Note 5)
18,471

 

Repayment of bank debt (Note 5)
(23,000
)
 

Proceeds from issuance of shares of Common Stock, net of issuance costs

 
1,198

Net cash (used in) provided by financing activities
(4,529
)
 
1,198

 
 
 
 
Foreign exchange gain on cash, cash equivalents and restricted cash and cash equivalents
474

 
1,154

 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents
1,431

 
(72,555
)
Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 11)
43,267

 
148,751

Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 11)
$
44,698

 
$
76,196

 
 
 
 
Supplemental cash flow disclosures (Note 11)
 

 
 


(See notes to the condensed consolidated financial statements)

6



Gran Tierra Energy Inc.
Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)
(Thousands of U.S. Dollars)
 
 
Three Months Ended March 31,
 
Year Ended December 31,
 
2017
 
2016
Share Capital
 
 
 
Balance, beginning of period
$
10,303

 
$
10,186

Issuance of Common Stock (Note 6)

 
117

Balance, end of period
10,303

 
10,303

 
 
 
 
Additional Paid in Capital
 

 
 

Balance, beginning of period
1,342,656

 
1,019,863

Issuance of Common Stock, net of share issuance costs (Note 6)

 
314,425

Exercise of stock options (Note 6)

 
5,347

Stock-based compensation (Note 6)
709

 
3,021

Balance, end of period
1,343,365

 
1,342,656

 
 
 
 
Deficit
 

 
 

Balance, beginning of period
(493,972
)
 
(28,407
)
Net income (loss)
12,771

 
(465,565
)
  Cumulative adjustment for accounting change related to tax reorganizations
  (Note 2)
124,476

 

Balance, end of period
(356,725
)
 
(493,972
)
 
 
 
 
Total Shareholders’ Equity
$
996,943

 
$
858,987


(See notes to the condensed consolidated financial statements)


7



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. The Company also has business activities in Peru and Brazil.

On February, 6, 2017, the Company announced that a purchase and sale agreement (the "Agreement") had been executed by a third party ("Purchaser") to purchase Gran Tierra's Brazil business unit through the acquisition of all of the equity interests in one of Gran Tierra's indirect subsidiaries, and the assignment of certain debt owed by the corporate entities comprising Gran Tierra's Brazil business unit to the Gran Tierra group of companies (the "Brazil Divestiture"). Upon completion of the Brazil Divestiture, the Purchaser will acquire all of Gran Tierra's assets and certain liabilities in Brazil, including its 100% working interest in the Tiê Field and all of Gran Tierra's interest in exploration rights and obligations held pursuant to concession agreements granted by the Agência Nacional do Petróleo, Gás Natural e Biocombustíveis of Brazil ("ANP").

The completion of the Brazil Divestiture is subject to the Purchaser obtaining financing, as well as customary closing conditions, including the receipt of required regulatory approval from the ANP. The consideration to be received by Gran Tierra on the completion of the Brazil Divestiture is $35 million, subject to adjustments, plus the assumption by the Purchaser of certain existing and potential liabilities of Gran Tierra's Brazil business unit. Pursuant to the Agreement, the Purchaser paid a deposit of $3.5 million on February 7, 2017, which is not refundable in the event the Purchaser is not successful in obtaining financing to complete the Brazil Divestiture. The economic effective date of the transaction would be on or before August 1, 2017, and Gran Tierra will continue to operate its Brazil business unit until the completion of the Brazil Divestiture.
 
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, 2016, included in the Company’s 2016 Annual Report on Form 10-K, filed with the SEC on March 1, 2017.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2016 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

Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory". The ASU provides guidance for the subsequent measurement of inventory and requires that inventory that is measured using average cost be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The implementation of this update did not materially impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

Employee Share-Based Payment Accounting

In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting". This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for

8



forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company elected to continue to estimate the total number of awards for which the requisite service period will not be rendered. The implementation of this update did not impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

Income Taxes - Intra-Entity Transfers of Assets Other than Inventory

At December 31, 2016, GAAP prohibited the recognition of current and deferred income taxes for intra-entity transfers until an asset leaves the consolidated group, therefore, the current income tax effect of tax reorganizations completed in 2016 was deferred and recognized as prepaid income taxes. At December 31, 2016, the Company's balance sheet included $54.1 million of prepaid income taxes, $12.3 million in current prepaid taxes and $41.8 million in long-term prepaid taxes, and $37.5 million of current income taxes payable relating to tax reorganizations completed in 2016.

In October 2016, the FASB issued ASU 2016-16, "Intra-Entity Transfers of Assets Other than Inventory." This ASU requires companies to recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the income statement as income tax expense or benefit in the period the sale or transfer occurs. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption was permitted as of the beginning of an annual reporting period. The ASU is required to be applied on a modified retrospective basis with a cumulative-effect adjustment directly to retained earnings in the period of adoption. The Company early adopted this ASU on January 1, 2017, and in the three months ending March 31, 2017, wrote off the income tax effects that had been deferred from past intercompany transactions to opening deficit. Prepaid tax of $54.1 million and deferred tax assets of $178.6 million were recorded directly to opening deficit at January 1, 2017. Deferred tax assets recorded upon adoption were assessed for realizability under ASC 740, and, valuation allowances were recognized on those deferred tax assets as necessary on the date of adoption. The adoption of ASU 2016-16 did not have any effect on the Company’s cash flows.

Restricted Cash and Cash Equivalents

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash". ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. The ASU was adopted on a retrospective basis to each period presented. The implementation of this ASU did not impact the Company's consolidated financial position or results of operations, and did not have a material impact on net cash used in investing activities for the three months ended March 31, 2017, or 2016.

Clarifying the Definition of a Business

In January 2017, the FASB issued ASU 2017-01, "Clarifying the Definition of a Business". ASU 2017-01 narrows the definition of a business and provides a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. ASU 2017-01 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. Early adoption was permitted and the Company adopted this ASU on January 1, 2017. The Company now applies an initial screen for determining whether a transaction involves an asset or a business. When substantially all of the fair value of the gross assets acquired is concentrated in a single identified asset, or group of similar identifiable assets, the set will not be a business and no goodwill or gain on acquisition will be recognized. If the screen is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create an output.

Simplifying the Test for Goodwill Impairment

In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment". ASU 2017-04 eliminates step 2 of the goodwill impairment test. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2019. Early adoption is permitted. At December 31, 2016, the Company performed a qualitative assessment of goodwill and, based on this assessment, no impairment of goodwill was identified. The Company did not have to perform step 2 of the goodwill impairment test.

9




3. Segment and Geographic Reporting
 
The Company is primarily engaged in the exploration and production of oil and natural gas. The Company’s reportable segments are Colombia, Peru and Brazil based on geographic organization. The All Other category represents the Company’s corporate activities. The Company evaluates reportable segment performance based on income or loss before income taxes. On February, 6, 2017, the Company announced that a purchase and sale agreement had been executed by the Purchaser to purchase Gran Tierra's Brazil business unit through the acquisition of all of the equity interests in one of Gran Tierra's indirect subsidiaries, and the assignment of certain debt owed by the corporate entities comprising Gran Tierra's Brazil business unit to the Gran Tierra group of companies (Note 1). The completion of the sale is subject to the Purchaser obtaining financing, as well as customary closing conditions, including the receipt of required regulatory approval from the ANP.

The following tables present information on the Company’s reportable segments and other activities:
 
Three Months Ended March 31, 2017
(Thousands of U.S. Dollars)
Colombia
 
Peru
 
Brazil
 
All Other
 
Total
Oil and natural gas sales
$
90,464

 
$

 
$
4,195

 
$

 
$
94,659

Depletion, depreciation and accretion
24,935

 
226

 
1,213

 
219

 
26,593

Asset impairment

 
283

 

 

 
283

General and administrative expenses
4,832

 
355

 
305

 
3,220

 
8,712

Income (loss) before income taxes
37,144

 
(513
)
 
1,520

 
(6,584
)
 
31,567

Segment capital expenditures
42,840

 
1,207

 
1,749

 
364

 
46,160

 
Three Months Ended March 31, 2016
(Thousands of U.S. Dollars)
Colombia
 
Peru
 
Brazil
 
All Other
 
Total
Oil and natural gas sales
$
56,300

 
$

 
$
1,103

 
$

 
$
57,403

Depletion, depreciation and accretion
35,736

 
141

 
718

 
317

 
36,912

Asset impairment
55,232

 
416

 
1,250

 

 
56,898

General and administrative expenses
3,265

 
409

 
292

 
3,083

 
7,049

(Loss) income before income taxes
(72,721
)
 
(712
)
 
(1,509
)
 
4,797

 
(70,145
)
Segment capital expenditures
21,986

 
1,268

 
2,720

 
206

 
26,180


 
As at March 31, 2017
(Thousands of U.S. Dollars)
Colombia
 
Peru
 
Brazil
 
All Other
 
Total
Property, plant and equipment
$
958,977

 
$
69,325

 
$
55,810

 
$
3,184

 
$
1,087,296

Goodwill
102,581

 

 

 

 
102,581

All other assets
211,693

 
11,111

 
3,559

 
16,053

 
242,416

Total Assets
$
1,273,251

 
$
80,436

 
$
59,369

 
$
19,237

 
$
1,432,293

 
 
 
 
 
 
 
 
 
 
 
As at December 31, 2016
(Thousands of U.S. Dollars)
Colombia
 
Peru
 
Brazil
 
All Other
 
Total
Property, plant and equipment
$
939,947

 
$
68,428

 
$
55,196

 
$
3,038

 
$
1,066,609

Goodwill
102,581

 

 

 

 
102,581

All other assets
177,393

 
10,848

 
1,619

 
8,846

 
198,706

Total Assets
$
1,219,921

 
$
79,276

 
$
56,815

 
$
11,884

 
$
1,367,896




10



4. Property, Plant and Equipment and Inventory
 
Property, Plant and Equipment

(Thousands of U.S. Dollars)
As at March 31, 2017
 
As at December 31, 2016
Oil and natural gas properties
 
 
 

  Proved
$
2,725,784

 
$
2,652,171

  Unproved
620,045

 
647,774

 
3,345,829

 
3,299,945

Other
29,744

 
29,445

 
3,375,573

 
3,329,390

Accumulated depletion, depreciation and impairment
(2,288,277
)
 
(2,262,781
)
 
$
1,087,296

 
$
1,066,609


Asset impairment for the three months ended March 31, 2017, and 2016 was as follows:

 
Three Months Ended March 31,
(Thousands of U.S. Dollars)
2017
 
2016
Impairment of oil and gas properties
$
283

 
$
56,234

Impairment of inventory

 
664

 
$
283

 
$
56,898


In the three months ended March 31, 2017 and 2016, the Company recorded impairment losses in its Peru cost center of $0.3 million and $0.4 million, respectively. In the three months ended March 31, 2017, the Company had no ceiling test impairment losses in its Colombia and Brazil cost centers. In the three months ended March 31, 2016, the Company recorded ceiling test impairment losses of $54.6 million and $1.3 million, respectively, in its Colombia and Brazil cost centers, as a result of low realized oil prices.

The Company follows the full cost method of accounting for its oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that estimates of future net revenues represent the fair market value of the Company's reserves. In accordance with GAAP, Gran Tierra used an average Brent price of $49.33 per bbl for the purposes of the March 31, 2017, ceiling test calculations (December 31, 2016 - $42.92; March 31, 2016 - $48.79; December 31, 2015 - $54.08).

Inventory

At March 31, 2017, oil and supplies inventories were $5.5 million and $1.8 million, respectively (December 31, 2016 - $6.0 million and $1.8 million, respectively). At March 31, 2017, the Company had 185 Mbbl of oil inventory (December 31, 2016 - 208 Mbbl). In the three months ended March 31, 2017, the Company recorded oil inventory impairment of $nil (three months ended March 31, 2016 - $0.7 million) related to lower oil prices.



11



5. Debt and Debt Issuance Costs

The Company's debt at March 31, 2017, and December 31, 2016, was as follows:

(Thousands of U.S. Dollars)
 
As at March 31, 2017
 
As at December 31, 2016
Convertible senior notes
 
$
115,000

 
$
115,000

Revolving credit facility
 
85,000

 
90,000

Unamortized debt issuance costs
 
(6,841
)
 
(7,917
)
Long-term debt
 
$
193,159

 
$
197,083


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

 
Three Months Ended March 31,
(Thousands of U.S. Dollars)
2017
 
2016
Contractual interest and other financing expenses
$
2,490

 
$
379

Amortization of debt issuance costs
605

 
140

 
$
3,095

 
$
519


6. Share Capital
 
The Company’s authorized share capital consists of 595,000,002 shares of capital stock, of which 570 million are designated as Common Stock, par value $0.001 per share, 25 million are designated as Preferred Stock, par value $0.001 per share, one share is designated as Special A Voting Stock, par value $0.001 per share, and one share is designated as Special B Voting Stock, par value $0.001 per share.

 
Shares of Common Stock
Exchangeable Shares of Gran Tierra Exchangeco Inc.
Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2016
390,807,194

4,812,592

3,387,302

Exchange of exchangeable shares
8,000

(8,000
)

Shares canceled
(4
)


Balance, March 31, 2017
390,815,190

4,804,592

3,387,302


Net Income (Loss) per Share

Basic net income (loss) per share is calculated by dividing net income (loss) attributable to common shareholders by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income (loss) per share is calculated by adjusting the weighted average number of shares of Common Stock and exchangeable shares outstanding for the dilutive effect, if any, of share equivalents. The Company uses the treasury stock method to determine the dilutive effect. This method assumes that all Common Stock equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase shares of Common Stock of the Company at the volume weighted average trading price of shares of Common Stock during the period.

Stock options and shares issuable upon conversion of the Convertible Senior Notes ("Notes") were excluded from the diluted loss per share calculation as the stock options and shares issuable upon conversion of the Notes were anti-dilutive.

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 three months ended March 31, 2017:

12



 
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, 2016
3,362,717

208,698

359,145

 
9,239,478

 
4.16

Granted
3,098,100

48,337


 
1,819,380

 
2.57

Exercised


(123,326
)
 

 

Forfeited


(2,558
)
 
(21,595
)
 
(5.71
)
Balance, March 31, 2017
6,460,817

257,035

233,261

 
11,037,263

 
3.90


Stock-based compensation expense for the three months ended March 31, 2017, and 2016, was $1.2 million and $1.5 million, respectively, and was primarily recorded in general and administrative ("G&A") expenses.

At March 31, 2017, there was $16.7 million (December 31, 2016 - $10.0 million) of unrecognized compensation cost related to unvested PSUs, RSUs and stock options which is expected to be recognized over a weighted average period of 2.2 years.

Weighted Average Shares Outstanding
 
 
 
Three Months Ended March 31,
 
 
2017
 
2016
Weighted average number of common and exchangeable shares outstanding
 
399,007,086

 
293,812,226

Shares issuable pursuant to stock options
 
635,484

 

Shares assumed to be purchased from proceeds of stock options
 
(596,456
)
 

Weighted average number of diluted common and exchangeable shares outstanding
 
399,046,114

 
293,812,226

 
For the three months ended March 31, 2017, 9,210,869 options, on a weighted average basis, (2016 - 12,667,761 options) were excluded from the diluted income (loss) per share calculation as the options were anti-dilutive.

7. Asset Retirement Obligation
 
Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:
 
Three Months Ended
 
Year Ended
(Thousands of U.S. Dollars)
March 31, 2017
 
December 31, 2016
Balance, beginning of period
$
43,357

 
$
33,224

Settlements
(195
)
 
(872
)
Liabilities associated with assets sold

 
(3,257
)
Liability incurred
190

 
2,606

Liabilities assumed in acquisition

 
15,723

Accretion
822

 
2,789

Revisions in estimated liability

 
(6,856
)
Balance, end of period
$
44,174

 
$
43,357

 
 
 
 
Asset retirement obligation - current
$
1,214

 
$
5,215

Asset retirement obligation - long-term
42,960

 
38,142

 
$
44,174

 
$
43,357


For the three months ended March 31, 2017, settlements included $nil cash payments with the balance in accounts payable and accrued liabilities at March 31, 2017. Revisions in estimated liabilities relate primarily to changes in estimates of asset

13



retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling asset retirement obligations. At March 31, 2017, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $12.6 million (December 31, 2016 - $12.0 million). These assets are accounted for as restricted cash and cash equivalents on the Company's interim unaudited condensed consolidated balance sheets.

8. Taxes
 
The Company's effective tax rate was 60% in the three months ended March 31, 2017, compared with 36% in the corresponding period in 2016. The Company's effective tax rate differed from the U.S. statutory rate of 35% primarily due
to an increase to 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 taxes, 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 $46.4 million as at March 31, 2017. 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, Gran Tierra has a number of other lawsuits and claims pending. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, Gran Tierra 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 as they are incurred or become probable and determinable.

Letters of credit and other credit support

At March 31, 2017, the Company had provided letters of credit and other credit support totaling $88.3 million (December 31, 2016 - $96.8 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 March 31, 2017, the Company’s financial instruments recognized in the balance sheet consist of: cash and cash equivalents; restricted cash and cash equivalents; accounts receivable; derivatives, accounts payable and accrued liabilities, long-term debt, PSU liability included in other long-term liabilities, and RSU liability included in accounts payable and accrued liabilities and other long-term liabilities.

Fair Value Measurement

The fair value of derivatives and RSU and PSU liabilities are being remeasured at the estimated fair value at the end of each reporting period.

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 RSU liability was estimated based on quoted market prices in an active market. The fair value of the PSU liability was estimated based on quoted market prices in an active market and an option pricing model such as the Monte Carlo simulation option-pricing models.


14



The fair value of derivatives, and RSU and PSU liabilities at March 31, 2017, and December 31, 2016, were as follows:

(Thousands of U.S. Dollars)
 
As at March 31, 2017
 
As at December 31, 2016
Commodity price derivative asset
 
$
879

 
$

Foreign currency derivative asset
 
546

 
578

 
 
$
1,425

 
$
578

 
 
 
 
 
Commodity price derivative liability
 
$

 
$
3,824

RSU, PSU and DSU liability
 
4,197

 
3,907

 
 
$
4,197

 
$
7,731


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

 
Three Months Ended March 31,
(Thousands of U.S. Dollars)
2017
 
2016
Commodity price derivative gain
$
(4,703
)
 
$

Foreign currency derivatives gain
(736
)
 

Trading securities loss

 
845

Financial instruments (gain) loss
$
(5,439
)
 
$
845


These gains and losses are presented as financial instruments gains or losses in the interim unaudited condensed consolidated statements of operations and cash flows.

Financial instruments not recorded at fair value include the Notes. At March 31, 2017, the carrying amount of the Notes was $110.1 million, which represents the aggregate principal amount less unamortized debt issuance costs, and the fair value was $128.5 million. 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 March 31, 2017, the fair value of the derivatives was determined using Level 2 inputs and the fair value of the PSU liability was determined using Level 3 inputs.

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 Notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure in the paragraph above regarding the fair value of the Company’s revolving credit facility was determined using an income approach using Level 3 inputs. The disclosure in the paragraph above regarding the fair value of the Notes was determined using Level 2 inputs based on the indicative pricing published by certain investment banks or trading levels of the 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 cash equivalents and restricted cash and cash equivalents was based on Level 1 inputs.


15



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 March 31, 2017, the Company had outstanding commodity price derivative positions as follows:
Period and type of instrument
Volume,
bopd
Reference
Sold Put ($/bbl)
Purchased Put
($/bbl)
Sold Call ($/bbl)
Collar: June 1, 2016 to May 31, 2017
10,000

ICE Brent
$
35

$
45

$
65

Collar: October 1, 2016 to December 31, 2017
5,000

ICE Brent
$
35

$
45

$
65

Collar: June 1, 2017 to December 31, 2017
10,000

ICE Brent
$
35

$
45

$
65


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 costs.

At March 31, 2017, 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 (1) (Thousands of U.S. Dollars)
Reference
Purchased Call
(COP)
Sold Put
(COP Weighted Average Rate)
Collar: April 1, 2017 to May 31, 2017
22,697

7,881

COP
3,100

3,340


(1) At March 31, 2017 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 March 31,
As at December 31,
 
 
2017
2016
2016
2015
Cash and cash equivalents
 
$
26,716

$
51,308

$
25,175

$
145,342

Restricted cash and cash equivalents - current
 
7,663

18,474

8,322

92

Restricted cash and cash equivalents -
included in other long-term assets
 
10,319

6,414

9,770

3,317

 
 
$
44,698

$
76,196

$
43,267

$
148,751


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

16



 
Three Months Ended March 31,
(Thousands of U.S. Dollars)
2017
 
2016
Accounts receivable and other long-term assets
$
(2,428
)
 
$
(2,513
)
Inventory
207

 
4,339

Prepaids
1,078

 
466

Accounts payable and accrued and other long-term liabilities
4,310

 
(5,975
)
Taxes receivable and payable
1,763

 
3,036

Net changes in assets and liabilities from operating activities
$
4,930

 
$
(647
)

The following table provides additional supplemental cash flow disclosures:

 
Three Months Ended March 31,
(Thousands of U.S. Dollars)
2017
 
2016
Non-cash investing activities:
 
 
 
Net liabilities related to property, plant and equipment, end of period
$
54,875

 
$
35,606


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Please see the cautionary language at the very beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements, as well as Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q and Part I, Item 1A “Risk Factors” in our 2016 Annual Report on Form 10-K.
 
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 Annual Report on Form 10-K, filed with the SEC on March 1, 2017.

Highlights
 
Acquisition of the Santana and Nancy-Burdine-Maxine Blocks

Subsequent to the end of the quarter, on April 27, 2017, we acquired the Santana and Nancy-Burdine-Maxine Blocks for cash consideration of $30.4 million. These two blocks were offered by Ecopetrol as part of an asset disposition process and are located in the Putumayo Basin.


17



Financial and Operational Highlights
 
Three Months Ended December 31
 
Three Months Ended March 31,
 
2016
 
2017
2016
% Change
Volumes (BOE)
 
 
 
 
 
Working Interest Production Before Royalties
2,854,852

 
2,689,146

2,330,539

15

Royalties
(438,656
)
 
(457,990
)
(256,803
)
78

Production NAR
2,416,196

 
2,231,156

2,073,736

8

Decrease in Inventory
19,688

 
1,584

240,424

(99
)
Sales(1)
2,435,884


2,232,740

2,314,160

(4
)
 
 
 
 
 
 
Average Daily Volumes (BOEPD)
 
 
 
 
 
Working Interest Production Before Royalties
31,031

 
29,879

25,610

17

Royalties
(4,768
)
 
(5,089
)
(2,822
)
80

Production NAR
26,263

 
24,790

22,788

9

Decrease in Inventory
214

 
18

2,642

(99
)
Sales(1)
26,477


24,808

25,430

(2
)
 
 
 
 
 


Operating Netback ($000s)
 
 
 
 
 
Oil and Natural Gas Sales
$
91,614

 
$
94,659

$
57,403

65

Operating Expenses
(24,472
)
 
(23,937
)
(19,067
)
26

Transportation Expenses
(7,458
)
 
(6,942
)
(12,328
)
(44
)
Operating Netback(2)
$
59,684

 
$
63,780

$
26,008

145

 
 
 
 
 
 
G&A Expenses, Including Stock-Based Compensation ($000s)
$
12,604

 
$
8,712

$
7,049

24

 
 
 
 
 
 
Net (Loss) Income ($000s)
$
(127,355
)
 
$
12,771

$
(45,032
)
128

EBITDA ($000s)(3)
$
30,745

 
$
61,538

$
24,184

154

 
 
 
 
 
 
Net Cash Provided by Operating Activities ($000s)
$
6,643

 
$
49,943

$
10,812

362

Funds Flow From Operations ($000s)(4)
$
36,186

 
$
45,026

$
11,563

289

 
 
 
 
 


Capital Expenditures ($000s)
$
58,219

 
$
46,160

$
26,180

76


 
As at
(Thousands of U.S. Dollars)
March 31, 2017
December 31, 2016
% Change
Cash, Cash Equivalents and Current Restricted Cash and Cash Equivalents
$
34,379

$
33,497

3

 
 
 
 
Revolving Credit Facility
$
85,000

$
90,000

(6
)
 
 
 
 
Convertible Senior Notes
$
115,000

$
115,000




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

Non-GAAP measures

18




Operating netback, EBITDA, and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views operating netback and EBITDA as financial performance measures and funds flow from operations as a liquidity measure. Investors are cautioned that these measures should not be construed as alternatives to net loss or other measures of financial performance or liquidity 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.

(2) Operating netback as presented is oil and gas sales net of royalties and operating and transportation expenses. Management believes that 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.

(3) EBITDA, as presented, is net income or loss adjusted for depletion, depreciation and accretion (“DD&A”) expenses, asset impairment, interest expense and income tax recovery or expense. Management uses these financial measures 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 these financial measures are also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income or loss to EBITDA is as follows:
 
Three Months Ended December 31
 
Three Months Ended March 31,
EBITDA - Non-GAAP Measure ($000s)
2016
 
2017
 
2016
Net (loss) income
$
(127,355
)
 
$
12,771

 
$
(45,032
)
Adjustments to reconcile net (loss) income to EBITDA
 
 
 
 
 
DD&A expenses
35,010

 
26,593

 
36,912

Asset impairment
146,934

 
283

 
56,898

Interest expense
6,303

 
3,095

 
519

Income tax (recovery) expense
(30,147
)
 
18,796

 
(25,113
)
EBITDA
$
30,745

 
$
61,538

 
$
24,184


(4) Funds flow from operations, as presented, is net cash provided by operating activities adjusted for net change in assets and liabilities from operating activities and cash settlement of asset retirement obligation. Management uses this financial measure to analyze liquidity and cash flows generated by our principal business activities prior to the consideration of how changes in assets and liabilities from operating activities and cash settlement of asset retirement obligation affect those cash flows, and believes that this financial measure is also useful supplemental information for investors to analyze our liquidity and financial results. A reconciliation from net cash provided by operating activities to funds flow from operations is as follows:
 
Three Months Ended December 31
 
Three Months Ended March 31,
Funds Flow From Operations - Non-GAAP Measure ($000s)
2016
 
2017
 
2016
Net cash provided by operating activities
$
6,643

 
49,943

 
$
10,812

Adjustments to reconcile net cash provided by operating activities to funds flow from operations
 
 
 
 
 
Net change in assets and liabilities from operating activities
29,434

 
(4,930
)
 
647

Cash settlement of asset retirement obligation
109

 
13

 
104

Funds flow from operations
$
36,186

 
$
45,026

 
$
11,563




19



Consolidated Results of Operations

 
 
Three Months Ended December 31
 
Three Months Ended March 31,
 
 
2016
 
2017
 
2016
 
% Change
(Thousands of U.S. Dollars)
 
 
 
 
 
 
 
 
Oil and natural gas sales
 
$
91,614

 
$
94,659

 
$
57,403

 
65

Operating expenses
 
24,472

 
23,937

 
19,067

 
26

Transportation expenses
 
7,458

 
6,942

 
12,328

 
(44
)
  Operating netback(1)
 
59,684

 
63,780

 
26,008

 
145

 
 
 
 
 
 
 
 
 
DD&A expenses
 
35,010

 
26,593

 
36,912

 
(28
)
Asset impairment
 
146,934

 
283

 
56,898

 
(100
)
G&A expenses before stock-based compensation
 
10,713

 
7,563

 
5,652

 
34

Stock-based compensation expense
 
1,891

 
1,149

 
1,397

 
(18
)
Transaction expenses
 

 

 
1,237

 
(100
)
Severance expenses
 
20

 

 
1,018

 
(100
)
Equity tax
 
45

 
1,224

 
3,051

 
(60
)
Foreign exchange (gain) loss
 
(2,528
)
 
(1,847
)
 
785

 
(335
)
Financial instruments loss (gain)
 
8,455

 
(5,439
)
 
845

 
(744
)
Interest expense
 
6,303

 
3,095

 
519

 
496

 
 
206,843

 
32,621

 
108,314

 
(70
)
 
 
 
 
 
 
 
 
 
(Adjustment to gain)/gain on acquisition
 
(10,783
)
 

 
11,712

 
(100
)
Interest income
 
440

 
408

 
449

 
(9
)
 
 
 
 
 
 
 
 

(Loss) income before income taxes
 
(157,502
)
 
31,567

 
(70,145
)
 
145

 
 
 
 
 
 
 
 
 
Current income tax expense
 
(8,442
)
 
(7,417
)
 
(2,023
)
 
267

Deferred income tax recovery (expense)
 
38,589

 
(11,379
)
 
27,136

 
142

 
 
30,147

 
(18,796
)
 
25,113

 
175

Net (loss) income
 
$
(127,355
)
 
$
12,771


$
(45,032
)

128

 
 
 
 
 
 
 
 

Sales Volumes
 
 
 
 
 
 
 

Oil and NGL's, bbl
 
2,394,098

 
2,195,214

 
2,292,116

 
(4
)
Natural gas, Mcf
 
250,713

 
225,158

 
132,265

 
70

Total sales volumes, BOE
 
2,435,884
 
2,232,740
 
2,314,160
 
(4
)
 
 
 
 
 
 
 
 
 
Total sales volumes, BOEPD
 
26,477

 
24,808

 
25,430

 
(2
)
 
 
 
 
 
 
 
 

Average Prices
 
 
 
 
 
 
 

Oil and NGL's per bbl
 
$
38.16

 
$
42.96

 
$
24.88

 
73

Natural gas per Mcf
 
$
1.05

 
$
1.52

 
$
2.83

 
(46
)
 
 
 
 
 
 
 
 


Brent Price per bbl
 
$
51.13

 
$
54.66

 
$
33.70

 
62

 
 
 
 
 
 
 
 
 

20



Consolidated Results of Operations per BOE Sales Volumes NAR
 
 
 
 
 
 
 


Oil and natural gas sales
 
$
37.61

 
$
42.40

 
$
24.81

 
71

Operating expenses
 
10.05

 
10.72

 
8.24

 
30

Transportation expenses
 
3.06

 
3.11

 
5.33

 
(42
)
  Operating netback(1)
 
24.50

 
28.57

 
11.24

 
154

 
 
 
 
 
 
 
 
 
DD&A expenses
 
14.37

 
11.91

 
15.95

 
(25
)
Asset impairment
 
60.32

 
0.13

 
24.59

 
(99
)
G&A expenses before stock-based compensation
 
4.39

 
3.39

 
2.45

 
38

Stock-based compensation expense
 
0.78

 
0.51

 
0.60

 
(15
)
Transaction expenses
 

 

 
0.53

 
(100
)
Severance expenses
 
0.01

 

 
0.44

 
(100
)
Equity tax
 
0.02

 
0.55

 
1.32

 
(58
)
Foreign exchange (gain) loss
 
(1.04
)
 
(0.83
)
 
0.34

 
344

Financial instruments loss (gain)
 
3.47

 
(2.44
)
 
0.37

 
759

Interest expense
 
2.59

 
1.39

 
0.22

 
532

 
 
84.91
 
14.61
 
46.81
 
(69
)
 
 
 
 
 
 
 
 
 
(Adjustment to gain)/gain on acquisition
 
(4.43
)
 

 
5.06

 
(100
)
Interest income
 
0.18

 
0.18

 
0.19

 
(5
)
 
 
 
 
 
 
 
 


(Loss) income before income taxes
 
(64.66
)
 
14.14

 
(30.32
)
 
147

Current income tax expense
 
(3.47
)
 
(3.32
)
 
(0.87
)
 
282

Deferred income tax recovery (expense)
 
15.84

 
(5.10
)
 
11.73

 
143

 
 
12.37

 
(8.42
)
 
10.86

 
178

Net (loss) income
 
$
(52.29
)
 
$
5.72

 
$
(19.46
)
 
129

 
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to non-GAAP measures disclosure above regarding this measure.

Oil and Gas Production and Sales Volumes, BOEPD

 
Three Months Ended March 31, 2017
 
Three Months Ended March 31, 2016
Average Daily Volumes (BOEPD)
Colombia
Brazil
Total
 
Colombia
Brazil
Total
Working Interest Production Before Royalties
28,481

1,398

29,879

 
24,886

724

25,610

Royalties
(4,868
)
(221
)
(5,089
)
 
(2,676
)
(146
)
(2,822
)
Production NAR
23,613

1,177

24,790

 
22,210

578

22,788

Decrease (Increase) in Inventory
7

11

18

 
2,647

(5
)
2,642

Sales
23,620

1,188

24,808

 
24,857

573

25,430

 
 
 
 
 
 
 
 
Royalties, % of Working Interest Production Before Royalties
17
%
16
%
17
%
 
11
%
20
%
11
%

Oil and gas production NAR for the three months ended March 31, 2017, increased by 9% to 24,790 BOEPD, compared with 22,788 BOEPD in the corresponding period in 2016. In the three months ended March 31, 2017, production increased primarily due to production from the Acordionero Field acquired in the PetroLatina acquisition and a successful drilling campaign in the Costayaco, Moqueta and Acordionero Fields in Colombia. In Brazil, oil and gas production NAR for the three months ended

21



March 31, 2017, increased by 599 BOEPD as a result of higher allowable oil production due to the commencement of gas compression as well as the sale of these gas volumes. Royalties as a percentage of production increased from the prior year commensurate with the increase in oil prices.

Oil and gas production NAR for the three months ended March 31, 2017, decreased 6% compared with the prior quarter due to well downtime from workovers in the Costayaco Field and pump failures in both Acordionero and Cumplidor.

Oil and gas sales volumes for the three months ended March 31, 2017, decreased by 2% to 24,808 BOEPD compared with 25,430 BOEPD in the corresponding period in 2016. Higher working interest production (4,269 BOEPD) was more than offset by the combination of higher royalty volumes (2,267 BOEPD) and smaller inventory decreases (2,624 BOEPD). During the three months ended March 31, 2017, oil inventory decreases accounted for 18 bopd of increased sales volumes compared with oil inventory decreases in the corresponding period in 2016, which accounted for 2,642 bopd of increased sales volumes.

Oil and gas sales volumes for the three months ended March 31, 2017, decreased by 6% to 24,808 BOEPD compared with 26,477 BOEPD in the prior quarter. Sales volumes decreased due to lower working interest production (1,152 BOEPD), higher royalty volumes (321 BOEPD) and the effect of inventory changes (196 BOEPD).

Operating Netbacks

 
Three Months Ended March 31, 2017
 
Three Months Ended March 31, 2016
(Thousands of U.S. Dollars)
Colombia
Brazil
Total
 
Colombia
Brazil
Total
Oil and Natural Gas Sales
$
90,464

$
4,195

$
94,659

 
$
56,300

$
1,103

$
57,403

Transportation Expenses
(6,765
)
(177
)
(6,942
)
 
(12,256
)
(72
)
(12,328
)
 
83,699

4,018

87,717

 
44,044

1,031

45,075

Operating Expenses
(23,156
)
(781
)
(23,937
)
 
(19,164
)
97

(19,067
)
Operating Netback(1)
$
60,543

$
3,237

$
63,780

 
$
24,880

$
1,128

$
26,008

 
 
 
 
 
 
 
 
U.S. Dollars Per BOE Sales Volumes NAR
 
 
 
 
 
 
 
Brent
$
54.66

$
54.66

$
54.66

 
$
33.70

$
33.70

$
33.70

Quality and Transportation Discounts
(12.11
)
(15.42
)
(12.26
)
 
(8.81
)
(12.57
)
(8.89
)
Average Realized Price
42.55

39.24

42.40

 
24.89

21.13

24.81

Transportation Expenses
(3.18
)
(1.66
)
(3.11
)
 
(5.42
)
(1.38
)
(5.33
)
Average Realized Price Net of Transportation Expenses
39.37

37.58

39.29

 
19.47

19.75

19.48

Operating Expenses
(10.89
)
(7.31
)
(10.72
)
 
(8.47
)
1.86

(8.24
)
Operating Netback(1)
$
28.48

$
30.27

$
28.57

 
$
11.00

$
21.61

$
11.24


(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to non-GAAP measures disclosure above regarding this measure.

Oil and gas sales for the three months ended March 31, 2017, increased by 65% to $94.7 million from $57.4 million in the comparable period in 2016 primarily due to increased 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 months ended March 31, 2017:

 
First Quarter 2017 Compared with Fourth Quarter 2016
First Quarter 2017 Compared with First Quarter 2016
Oil and natural gas sales for the comparative period
$
91,614

$
57,403

Realized sales price increase effect
10,685

39,276

Sales volume decrease effect
(7,640
)
(2,020
)
Oil and natural gas sales for period ended March 31, 2017
$
94,659

$
94,659



22



Average realized prices for the three months ended March 31, 2017, increased by 71%, commensurate with the increase in benchmark oil prices. Average Brent oil prices for the three months ended March 31, 2017, increased by 62%. In Brazil, in the three months ended March 31, 2017, the differential between our average realized price and Brent per BOE increased as a result of higher gas sales.

Oil and gas sales for the three months ended March 31, 2017, increased by 3% to $94.7 million from $91.6 million compared with the prior quarter primarily due to increased realized oil prices, partially offset by lower sales volumes. Average realized prices increased by 13% to $42.40 per BOE for the three months ended March 31, 2017, compared with $37.61 per BOE in the prior quarter. Average Brent oil prices for the three months ended March 31, 2017, increased by 7% to $54.66 per bbl, compared with $51.13 per bbl in the prior quarter.

During periods of CENIT S.A-operated Trans-Andean oil pipeline (the "OTA pipeline”) disruptions, we have multiple transportation alternatives. Each transportation route has varying effects on realized prices and transportation expenses. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for the three months ended March 31, 2017 and 2016 and the prior quarter:

 
 
Three Months Ended December 31
 
Three Months Ended March 31,
 
 
2016
 
2017
2016
Volume transported through pipeline
 
29
%
 
25
%
67
%
Volume sold at wellhead, trucking
 
49
%
 
50
%
17
%
Volume sold not at wellhead, trucking
 
22
%
 
25
%
16
%
 
 
100
%
 
100
%
100
%

Volume not sold at the wellhead receives a higher realized price, but incurs higher transportation expense. Volume sold at the wellhead has the opposite effect of lower realized price, offset by lower transportation expense.

Transportation expenses for the three months ended March 31, 2017, decreased by 44% to $6.9 million compared with the corresponding period in 2016. On a per BOE basis, transportation expenses decreased by 42% to $3.11 per BOE from $5.33 per BOE in the corresponding period in 2016. The decrease in transportation expenses per BOE was due to a higher percentage of volumes sold at the wellhead, as noted in the table above, and the use of alternative transportation routes, which had lower costs per BOE than the routes used in 2016.

Transportation expenses for the three months ended March 31, 2017, decreased 7% to $6.9 million compared with $7.5 million in the prior quarter. On a per BOE basis, transportation expenses increased by 2% to $3.11 from $3.06 in the prior quarter. The increase was primarily due to a higher percentage of trucked sales in the current quarter.

The following table shows the variance in our average realized prices net of transportation expenses in Colombia for the three months ended March 31, 2017 compared with the comparative period in 2016 and the prior quarter:

U.S. Dollars Per BOE Sales Volumes NAR
First Quarter 2017 Compared with Fourth Quarter 2016
First Quarter 2017 Compared with First Quarter 2016
Average realized price net of transportation expenses for the comparative period
$
34.50

$
19.47

Increase in benchmark prices
3.53

20.96

Decrease (increase) in quality and transportation discounts
1.43

(3.30
)
(Higher) lower transportation expenses
(0.09
)
2.24

Average realized price net of transportation expenses for period ended March 31, 2017
$
39.37

$
39.37


Operating expenses for the three months ended March 31, 2017, increased by 26% to $23.9 million, compared with the corresponding period in 2016. On a per BOE basis, operating expenses increased by 30% to $10.72 per BOE from $8.24 per BOE in the corresponding period in 2016.

23




Colombian operating expense for the three months ended March 31, 2017, increased by $2.42 per BOE compared with the corresponding period in 2016. Workover expenses in Colombia increased by $0.74 per BOE compared with the corresponding period in 2016, and the remainder of the increase is primarily due to the cost of renting additional water injection equipment, and the effect of lower sales volumes in the three months ended March 31, 2017.

In Brazil, the comparative period in 2016 included a $7.97 per bbl reduction in operating expenses based on volumes sold in Brazil, after we settled a one-time penalty for less than estimated.

Operating expenses decreased by 2% to $23.9 million in the three months ended March 31, 2017, compared with $24.5 million in the prior quarter. On a per BOE basis, operating expenses increased by 7% to $10.72 per BOE for the three months ended March 31, 2017, from $10.05 per BOE in the prior quarter primarily due to lower sales volumes and the relationship between fixed and variable costs.

DD&A Expenses

 
Three Months Ended March 31, 2017
 
Three Months Ended March 31, 2016
 
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
$
24,935

$
11.73

 
$
35,736

$
15.80

Brazil
1,213

11.35

 
718

13.75

Peru
226


 
141


Corporate
219


 
317


 
$
26,593

$
11.91

 
$
36,912

$
15.95


DD&A expenses for the three months ended March 31, 2017, decreased to $26.6 million ($11.91 per BOE) from $36.9 million ($15.95 per BOE) in the corresponding period in 2016. DD&A expenses decreased by 17% to $11.91 per BOE for the three months ended March 31, 2017, from $14.37 per BOE in the prior quarter. On a per BOE basis, the decrease was due to lower costs in the depletable base and increased proved reserves.

Asset Impairment

We follow the full cost method of accounting for our oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices dis