Document
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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| | |
ý | | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2018
or
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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)
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| | |
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 April 27, 2018, the following number of shares of the registrant’s capital stock were outstanding: 385,258,378 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 1,688,889 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 4,078,174 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.
Gran Tierra Energy Inc.
Quarterly Report on Form 10-Q
Quarterly Period Ended March 31, 2018
Table of contents
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| | Page |
PART I | Financial Information | |
Item 1. | Financial Statements | |
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | |
Item 4. | Controls and Procedures | |
| | |
PART II | Other Information | |
Item 1. | Legal Proceedings | |
Item 1A. | Risk Factors | |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | |
Item 6. | Exhibits | |
SIGNATURES | |
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:
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| | | |
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)
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| | | | | | | |
| Three Months Ended March 31, |
| 2018 | | 2017 |
OIL AND NATURAL GAS SALES (NOTES 3 and 7) | $ | 138,228 |
| | $ | 94,659 |
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EXPENSES | | | |
Operating | 26,265 |
| | 23,937 |
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Transportation | 6,997 |
| | 6,942 |
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Depletion, depreciation and accretion (Note 3) | 39,461 |
| | 26,593 |
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Asset impairment | — |
| | 283 |
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General and administrative (Note 3) | 11,160 |
| | 8,712 |
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Equity tax | — |
| | 1,224 |
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Foreign exchange gain | (942 | ) | | (1,847 | ) |
Financial instruments loss (gain) (Note 10) | 6,946 |
| | (5,439 | ) |
Interest expense (Note 5) | 5,495 |
| | 3,095 |
|
| 95,382 |
| | 63,500 |
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INTEREST INCOME | 786 |
| | 408 |
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INCOME BEFORE INCOME TAXES (NOTE 3) | 43,632 |
| | 31,567 |
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INCOME TAX EXPENSE | | | |
Current (Note 8) | 12,289 |
| | 7,417 |
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Deferred (Note 8) | 13,482 |
| | 11,379 |
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| 25,771 |
| | 18,796 |
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NET INCOME AND COMPREHENSIVE INCOME | $ | 17,861 |
| | $ | 12,771 |
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NET INCOME PER SHARE | | | |
- BASIC AND DILUTED | $ | 0.05 |
| | $ | 0.03 |
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WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6) | 391,294,042 |
| | 399,007,086 |
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WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6) | 391,379,013 |
| | 399,046,114 |
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(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 March 31, 2018 | | As at December 31, 2017 |
| | | |
ASSETS | | | |
Current Assets | | | |
Cash and cash equivalents (Note 11) | $ | 160,474 |
| | $ | 12,326 |
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Restricted cash and cash equivalents (Note 11) | 3,294 |
| | 11,787 |
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Accounts receivable | 49,239 |
| | 45,353 |
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Investment (Note 10) | 21,265 |
| | 25,055 |
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Derivatives (Note 10) | 3,769 |
| | 302 |
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Taxes receivable | 55,024 |
| | 40,831 |
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Other current assets | 10,952 |
| | 9,591 |
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Total Current Assets | 304,017 |
| | 145,245 |
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Oil and Gas Properties (using the full cost method of accounting) | |
| | |
|
Proved | 676,520 |
| | 629,081 |
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Unproved | 452,865 |
| | 464,948 |
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Total Oil and Gas Properties | 1,129,385 |
| | 1,094,029 |
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Other capital assets | 4,802 |
| | 5,195 |
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Total Property, Plant and Equipment (Notes 3 and 4) | 1,134,187 |
| | 1,099,224 |
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Other Long-Term Assets | |
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Deferred tax assets | 43,547 |
| | 57,310 |
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Investment (Note 10) | 15,964 |
| | 19,147 |
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Other long-term assets (Note 11) | 6,492 |
| | 6,112 |
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Goodwill (Note 3) | 102,581 |
| | 102,581 |
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Total Other Long-Term Assets | 168,584 |
| | 185,150 |
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Total Assets (Note 3) | $ | 1,606,788 |
| | $ | 1,429,619 |
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LIABILITIES AND SHAREHOLDERS’ EQUITY | |
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Current Liabilities | |
| | |
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Accounts payable and accrued liabilities | $ | 126,756 |
| | $ | 125,876 |
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Derivatives (Note 10) | 21,672 |
| | 21,151 |
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Taxes payable | 23,203 |
| | 9,324 |
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Asset retirement obligation | 111 |
| | 323 |
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Equity compensation award liability (Note 10) | 8,633 |
| | 295 |
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Total Current Liabilities | 180,375 |
| | 156,969 |
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Long-Term Liabilities | |
| | |
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Long-term debt (Notes 5 and 10) | 397,568 |
| | 256,542 |
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Deferred tax liabilities | 26,467 |
| | 28,417 |
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Asset retirement obligation | 33,405 |
| | 31,241 |
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Equity compensation award liability (Note 10) | 5,724 |
| | 11,135 |
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Other long-term liabilities | 9,610 |
| | 8,980 |
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Total Long-Term Liabilities | 472,774 |
| | 336,315 |
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Contingencies (Note 9) |
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Shareholders’ Equity | |
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Common Stock (Note 6) (384,959,730 and 385,191,042 shares of Common Stock and 5,908,065 and 6,111,665 exchangeable shares, par value $0.001 per share, issued and outstanding as at March 31, 2018, and December 31, 2017, respectively) | 10,295 |
| | 10,295 |
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Additional paid in capital | 1,326,687 |
| | 1,327,244 |
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Deficit | (383,343 | ) | | (401,204 | ) |
Total Shareholders’ Equity | 953,639 |
| | 936,335 |
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Total Liabilities and Shareholders’ Equity | $ | 1,606,788 |
| | $ | 1,429,619 |
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(See notes to the condensed consolidated financial statements)
Gran Tierra Energy Inc.
Condensed Consolidated Statements of Cash Flows (Unaudited)
(Thousands of U.S. Dollars)
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| Three Months Ended March 31, |
| 2018 | | 2017 |
Operating Activities | | | |
Net income | $ | 17,861 |
| | $ | 12,771 |
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Adjustments to reconcile net income to net cash provided by operating activities: | | | |
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Depletion, depreciation and accretion (Note 3) | 39,461 |
| | 26,593 |
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Asset impairment | — |
| | 283 |
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Deferred tax expense | 13,482 |
| | 11,379 |
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Stock-based compensation (Note 6) | 3,309 |
| | 1,203 |
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Amortization of debt issuance costs (Note 5) | 670 |
| | 605 |
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Cash settlement of restricted share units | (120 | ) | | (318 | ) |
Unrealized foreign exchange gain | (1,044 | ) | | (2,819 | ) |
Financial instruments loss (gain) (Note 10) | 6,946 |
| | (5,439 | ) |
Cash settlement of financial instruments (Note 10) | (5,817 | ) | | 768 |
|
Cash settlement of asset retirement obligation | (192 | ) | | (13 | ) |
Net change in assets and liabilities from operating activities (Note 11) | (3,464 | ) | | 4,930 |
|
Net cash provided by operating activities | 71,092 |
| | 49,943 |
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Investing Activities | |
| | |
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Additions to property, plant and equipment (Note 3) | (72,694 | ) | | (46,160 | ) |
Deposit received for sale of Brazil business unit | — |
| | 3,500 |
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Changes in non-cash investing working capital | 1,957 |
| | (1,797 | ) |
Net cash used in investing activities | (70,737 | ) | | (44,457 | ) |
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Financing Activities | |
| | |
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Proceeds from bank debt, net of issuance costs (Note 5) | 4,988 |
| | 18,471 |
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Repayment of bank debt (Note 5) | (153,000 | ) | | (23,000 | ) |
Proceeds exercise of stock options (Note 6) | 74 |
| | — |
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Repurchase of shares of Common Stock (Note 6) | (1,194 | ) | | — |
|
Proceeds from issuance of Senior Notes, net of issuance costs (Note 5) | 288,368 |
| | — |
|
Net cash provided by (used in) financing activities | 139,236 |
| | (4,529 | ) |
| | | |
Foreign exchange gain on cash, cash equivalents and restricted cash and cash equivalents | 663 |
| | 474 |
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| | | |
Net increase in cash, cash equivalents and restricted cash and cash equivalents | 140,254 |
| | 1,431 |
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Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 11) | 26,678 |
| | 43,267 |
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Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 11) | $ | 166,932 |
| | $ | 44,698 |
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| | | |
Supplemental cash flow disclosures (Note 11) | |
| | |
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(See notes to the condensed consolidated financial statements)
Gran Tierra Energy Inc.
Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)
(Thousands of U.S. Dollars)
|
| | | | | | | |
| Three Months Ended March 31, | | Three Months Ended March 31, |
| 2018 | | 2017 |
Share Capital | | | |
Balance, beginning of period | $ | 10,295 |
| | $ | 10,303 |
|
Balance, end of period | 10,295 |
| | 10,303 |
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| | | |
Additional Paid in Capital | |
| | |
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Balance, beginning of period | 1,327,244 |
| | 1,342,656 |
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Exercise of stock options (Note 6) | 74 |
| | — |
|
Stock-based compensation (Note 6) | 563 |
| | 709 |
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Repurchase of Common Stock (Note 6) | (1,194 | ) | | — |
|
Balance, end of period | 1,326,687 |
| | 1,343,365 |
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| | | |
Deficit | |
| | |
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Balance, beginning of period | (401,204 | ) | | (493,972 | ) |
Net income (loss) | 17,861 |
| | 12,771 |
|
Cumulative adjustment for accounting change related to tax reorganizations | — |
| | 124,476 |
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Balance, end of period | (383,343 | ) | | (356,725 | ) |
| | | |
Total Shareholders’ Equity | $ | 953,639 |
| | $ | 996,943 |
|
(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 considered 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 clarifies 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 on the Company’s consolidated financial position, results of operations or cash flows or disclosure.
3. Segment and Geographic Reporting
The Company is primarily engaged in the exploration and production of oil and natural gas. Commencing in 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 its Peru business unit effective December 18, 2017, Brazil and Peru were reportable segments. The "All Other" category represents the Company’s corporate, Brazil and Peru activities until the date of sale.
The following tables present information on the Company’s reportable segments and other activities:
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| Three Months Ended March 31, 2018 |
(Thousands of U.S. Dollars) | Colombia | | All Other | | Total |
Oil and natural gas sales | $ | 138,228 |
| | $ | — |
| | $ | 138,228 |
|
Depletion, depreciation and accretion | 38,499 |
| | 962 |
| | 39,461 |
|
General and administrative expenses | 6,809 |
| | 4,351 |
| | 11,160 |
|
Income (loss) before income taxes | 61,151 |
| | (17,519 | ) | | 43,632 |
|
Segment capital expenditures | 72,561 |
| | 133 |
| | 72,694 |
|
| | | | | |
| Three Months Ended March 31, 2017 |
(Thousands of U.S. Dollars) | Colombia | | All Other | | Total |
Oil and natural gas sales | $ | 90,464 |
| | $ | 4,195 |
| | $ | 94,659 |
|
Depletion, depreciation and accretion | 24,935 |
| | 1,658 |
| | 26,593 |
|
General and administrative expenses | 4,832 |
| | 3,880 |
| | 8,712 |
|
Income (loss) before income taxes | 37,144 |
| | (5,577 | ) | | 31,567 |
|
Segment capital expenditures | 42,840 |
| | 3,320 |
| | 46,160 |
|
|
| | | | | | | | | | | |
| As at March 31, 2018 |
(Thousands of U.S. Dollars) | Colombia | | All Other | | Total |
Property, plant and equipment | $ | 1,132,626 |
| | $ | 1,561 |
| | $ | 1,134,187 |
|
Goodwill | 102,581 |
| | — |
| | 102,581 |
|
All other assets | 182,440 |
| | 187,580 |
| | 370,020 |
|
Total Assets | $ | 1,417,647 |
| | $ | 189,141 |
| | $ | 1,606,788 |
|
| | | | | |
| 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
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| | | | | | | |
(Thousands of U.S. Dollars) | As at March 31, 2018 | | As at December 31, 2017 |
Oil and natural gas properties | | | |
|
Proved | $ | 2,896,700 |
| | $ | 2,810,796 |
|
Unproved | 452,865 |
| | 464,948 |
|
| 3,349,565 |
| | 3,275,744 |
|
Other | 23,633 |
| | 26,401 |
|
| 3,373,198 |
| | 3,302,145 |
|
Accumulated depletion, depreciation and impairment | (2,239,011 | ) | | (2,202,921 | ) |
| $ | 1,134,187 |
| | $ | 1,099,224 |
|
The Company used an average Brent price of $56.92 per bbl for the purposes of the March 31, 2018 ceiling test calculations (December 31, 2017 - $54.19).
5. Debt and Debt Issuance Costs
The Company's debt at March 31, 2018 and December 31, 2017 was as follows:
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| | | | | | | |
(Thousands of U.S. Dollars) | As at March 31, 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 | (17,432 | ) | | (6,458 | ) |
Long-term debt | $ | 397,568 |
| | $ | 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 $288.4 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:
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| | | | | | | |
| Three Months Ended March 31, |
(Thousands of U.S. Dollars) | 2018 | | 2017 |
Contractual interest and other financing expenses | $ | 4,825 |
| | $ | 2,490 |
|
Amortization of debt issuance costs | 670 |
| | 605 |
|
| $ | 5,495 |
| | $ | 3,095 |
|
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 $0.001 per share.
|
| | | | | | |
| Shares of Common Stock | Exchangeable Shares of Gran Tierra Exchangeco Inc. | Exchangeable Shares of Gran Tierra Goldstrike Inc. |
Balance, December 31, 2017 | 385,191,042 |
| 4,422,776 |
| 1,688,889 |
|
Options exercised | 30,000 |
| — |
| — |
|
Shares repurchased and canceled | (464,912 | ) | — |
| — |
|
Exchange of exchangeable shares | 203,600 |
| (203,600 | ) | — |
|
Balance, March 31, 2018 | 384,959,730 |
| 4,219,176 |
| 1,688,889 |
|
On March 7, 2018, the Company announced that it intended to implement a share repurchase program (the “2018 Program”) through the facilities of the Toronto Stock Exchange ("TSX") and eligible alternative trading platforms in Canada. Under the 2018 Program, the Company is able to purchase at prevailing market prices up to 19,269,732 shares of Common Stock, representing approximately 5.00% of the issued and outstanding shares of Common Stock as of March 8, 2018. Shares purchased pursuant to 2018 Program will be canceled. The 2018 Program will expire on March 11, 2019, or earlier if the 5.00% share maximum is reached.
Equity Compensation Awards
The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock option activity for the three months ended March 31, 2018:
|
| | | | | | | | | | | |
| PSUs | DSUs | RSUs | | Stock Options |
| Number of Outstanding Share Units | Number of Outstanding Share Units | Number of Outstanding Share Units | | Number of Outstanding Stock Options | Weighted Average Exercise Price/Stock Option ($) |
Balance, December 31, 2017 | 6,131,951 |
| 455,768 |
| 122,090 |
| | 8,960,692 |
| 3.65 |
|
Granted | 3,305,486 |
| 67,926 |
| — |
| | 1,890,413 |
| 2.47 |
|
Exercised | — |
| — |
| (48,600 | ) | | (30,000 | ) | (2.46 | ) |
Forfeited | (108,195 | ) | — |
| (1,822 | ) | | (349,878 | ) | (5.17 | ) |
Expired | — |
| — |
| — |
| | (8,334 | ) | (3.50 | ) |
Balance, March 31, 2018 | 9,329,242 |
| 523,694 |
| 71,668 |
| | 10,462,893 |
| 3.39 |
|
Stock-based compensation expense for the three months ended March 31, 2018, was $3.3 million and was primarily recorded in general and administrative ("G&A") expenses (three months ended March 31, 2017 - $1.2 million).
At March 31, 2018, there was $22.0 million (December 31, 2017 - $13.7 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 2.0 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 March 31, |
| 2018 | | 2017 |
Weighted average number of common and exchangeable shares outstanding | 391,294,042 |
| | 399,007,086 |
|
Shares issuable pursuant to stock options | 867,427 |
| | 635,484 |
|
Shares assumed to be purchased from proceeds of stock options | (782,456 | ) | | (596,456 | ) |
Weighted average number of diluted common and exchangeable shares outstanding | 391,379,013 |
| | 399,046,114 |
|
For the three months ended March 31, 2018, 8,599,422 options, on a weighted average basis, (three months ended March 31, 2017 - 9,210,869 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 anti-dilutive and excluded from the diluted income per share calculation.
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 quality each month. For the three months ended March 31, 2018, 100% (three months ended March 31, 2017 - 100%) of the Company's revenue resulted from oil sales. In the three months ended March 31, 2018, quality and transportation discounts were 16% of the ICE Brent price (three months ended March 31, 2017 - 22%). During the three months ended March 31, 2018, the Company's production was sold primarily to four major customers in Colombia (three months ended March 31, 2017 - three).
As at March 31, 2018, accounts receivable included $7.1 million of accrued sales revenue which related to March 2018 production (December 31, 2017 - $11.1 million which related to December 31, 2017 production). December 31, 2017 accrued sales revenue was collected during the three months ended March 31, 2018 without significant adjustment to revenue for that period.
8. Taxes
The Company's effective tax rate was 59% in the three months ended March 31, 2018, compared with 60% in the comparable period in 2017. Current income tax expense was higher in the three months ended March 31, 2018, compared with the corresponding period in 2017, primarily as a result of higher taxable income in Colombia. The deferred income tax expense of $13.5 million for the three months ended March 31, 2018, was primarily due to excess tax depreciation compared with accounting depreciation in Colombia.
For the three months ended March 31, 2018, the difference between the effective tax rate of 59% and the 21% U.S. statutory rate was primarily due to an increase to the impact of foreign taxes, valuation allowance, other permanent differences, non-deductible third party royalty in Colombia, stock based compensation, other local taxes and foreign currency translation.
For the comparable period in 2017, the effective 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 $51.8 million as at March 31, 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 March 31, 2018, the Company had provided letters of credit and other credit support totaling $76.5 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 March 31, 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 award (PSU, DSU and RSU) 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 Sterling Resources Ltd. ("Sterling") was estimated using quoted prices at March 31, 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 Sterling'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 and RSU liabilities were estimated based on quoted market prices in an active market.
The fair value of derivatives and RSU, PSU and DSU liabilities at March 31, 2018, and December 31, 2017, were as follows:
|
| | | | | | | |
(Thousands of U.S. Dollars) | As at March 31, 2018 | | As at December 31, 2017 |
Investment - current and long-term assets | $ | 37,229 |
| | $ | 44,202 |
|
Foreign currency derivative asset | 3,769 |
| | 302 |
|
| $ | 40,998 |
| | $ | 44,504 |
|
| | | |
Commodity price derivative liability | $ | 21,672 |
| | $ | 21,151 |
|
Equity compensation award liability - current and long-term | 14,357 |
| | 11,430 |
|
| $ | 36,029 |
| | $ | 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 March 31, |
(Thousands of U.S. Dollars) | 2018 | | 2017 |
Commodity price derivative loss (gain) | $ | 4,995 |
| | $ | (4,703 | ) |
Foreign currency derivatives gain | (3,970 | ) | | (736 | ) |
Investment loss | 5,921 |
| | — |
|
Financial instruments loss (gain) | $ | 6,946 |
| | $ | (5,439 | ) |
These gains and losses are presented as financial instrument gains and losses in the interim unaudited condensed consolidated statements of operations and cash flows.
Investment loss for the three months ended March 31, 2018 related to the fair value loss on the Sterling shares Gran Tierra received or subscribed for in connection with the sale of its Peru business unit in December 2017. For the three months ended March 31, 2018, this investment loss was unrealized.
Financial instruments not recorded at fair value include the Senior Notes and the Convertible Notes. At March 31, 2018, the carrying amounts of the Senior Notes and the Convertible Notes were $288.5 million and $111.2 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $292.5 million and $130.0 million, respectively. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities.
At March 31, 2018, the fair value of the current portion of the investment, DSU and RSU 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:
|
| | | | | | | |
| Three Months Ended | | Year Ended |
| March 31, 2018 | | December 31, 2017 |
(Thousands of U.S. Dollars) | | | |
Opening balance | $ | 19,147 |
| | $ | — |
|
Acquisition | — |
| | 19,091 |
|
Unrealized valuation (loss) gain | (2,703 | ) | | 56 |
|
Unrealized foreign exchange loss | (480 | ) | | — |
|
Closing balance | $ | 15,964 |
| | $ | 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 March 31, 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: April 1, to December 31, 2018 | 5,000 |
| ICE Brent | $ | 55.90 |
| n/a |
|
Participating Swaps: April 1, to December 31, 2018 | 5,000 |
| ICE Brent | $ | 52.50 |
| $ | 56.11 |
|
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 March 31, 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: April 1, 2018 to December 31, 2018 | 130,500 |
| 46,935 |
| COP | 3,000 |
| 3,107 |
|
(1) At March 31, 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 March 31, | | As at December 31, |
| 2018 | 2017 | | 2017 | 2016 |
Cash and cash equivalents | $ | 160,474 |
| $ | 26,716 |
| | $ | 12,326 |
| $ | 25,175 |
|
Restricted cash and cash equivalents - current | 3,294 |
| 7,663 |
| | 11,787 |
| 8,322 |
|
Restricted cash and cash equivalents - long-term (included in other long-term assets) | 3,164 |
| 10,319 |
| | 2,565 |
| 9,770 |
|
| $ | 166,932 |
| $ | 44,698 |
| | $ | 26,678 |
| $ | 43,267 |
|
Net changes in assets and liabilities from operating activities were as follows:
|
| | | | | | | |
| Three Months Ended March 31, |
(Thousands of U.S. Dollars) | 2018 | | 2017 |
Accounts receivable and other long-term assets | $ | (1,982 | ) | | $ | (2,428 | ) |
Derivatives | 1,847 |
| | — |
|
Inventory | (1,785 | ) | | 207 |
|
Prepaids | 1,498 |
| | 1,078 |
|
Accounts payable and accrued and other long-term liabilities | (2,495 | ) | | 4,310 |
|
Taxes receivable and payable | (547 | ) | | 1,763 |
|
Net changes in assets and liabilities from operating activities | $ | (3,464 | ) | | $ | 4,930 |
|
The following table provides additional supplemental cash flow disclosures:
|
| | | | | | | |
| Three Months Ended March 31, |
(Thousands of U.S. Dollars) | 2018 | | 2017 |
Non-cash investing activities: | | | |
Net liabilities related to property, plant and equipment, end of period | $ | 70,108 |
| | $ | 54,875 |
|
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 first quarter of 2018(1)
| |
• | Working interest production before royalties was 35,075 BOEPD, 23% higher compared with 28,481 BOEPD in the first quarter of 2017. |
| |
• | Production net after royalty ("NAR") was 28,189 BOEPD, 19% higher than the first quarter of 2017. We increased production NAR largely because of production from development activities in the Acordionero Field. |
| |
• | Oil and natural gas sales volumes were 27,203 BOEPD, 15% higher than the first quarter of 2017. |
| |
• | Net income was $17.9 million compared with $12.8 million in the first quarter of 2017. |
| |
• | Funds flow from operations(3) increased by 66% to $74.7 million compared with the first quarter of 2017. |
| |
• | Oil and gas sales per BOE were $56.46, 33% higher than the first quarter of 2017. Brent price increased 23% compared with the first quarter of 2017. |
| |
• | Operating netback(3) per BOE was $42.87 per BOE, 51% higher compared with the first quarter of 2017. |
| |
• | Operating expenses per BOE were $10.73 per BOE, which was comparable with the first quarter of 2017. |
| |
• | Transportation expenses per BOE were $2.86 per BOE, 10% lower compared with the first quarter of 2017. The decrease was due to a higher percentage of volumes sold at the wellhead and the increased use of transportation routes that had lower costs than the routes used in the first quarter of 2017. |
| |
• | General and administrative ("G&A") expenses before stock-based compensation per BOE decreased by 4% to $3.26 per BOE compared with the first quarter of 2017. |
(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.
|
| | | | | | | | | | | | |
(Thousands of U.S. Dollars, unless otherwise indicated) | Three Months Ended December 31, | | Three Months Ended March 31, |
| 2017 | | 2018 | 2017 | % Change |
Average Daily Volumes (BOEPD) | | | | | |
Consolidated | | | | | |
Working Interest Production Before Royalties | 34,477 |
| | 35,075 |
| 29,879 |
| 17 |
|
Royalties | (6,114 | ) | | (6,886 | ) | (5,089 | ) | 35 |
|
Production NAR | 28,363 |
| | 28,189 |
| 24,790 |
| 14 |
|
(Increase) Decrease in Inventory | (194 | ) | | (986 | ) | 18 |
| — |
|
Sales(2) | 28,169 |
|
| 27,203 |
| 24,808 |
| 10 |
|
| | | | |
|
|
Colombia | | | | | |
Working Interest Production Before Royalties | 34,477 |
| | 35,075 |
| 28,481 |
| 23 |
|
Royalties | (6,114 | ) | | (6,886 | ) | (4,868 | ) | 41 |
|
Production NAR | 28,363 |
| | 28,189 |
| 23,613 |
| 19 |
|
(Increase) Decrease in Inventory | (194 | ) | | (986 | ) | 7 |
| — |
|
Sales(2) | 28,169 |
| | 27,203 |
| 23,620 |
| 15 |
|
| | | | | |
Net Income (Loss) | $ | (40,802 | ) | | $ | 17,861 |
| $ | 12,771 |
| 40 |
|
| | | | |
|
|
Operating Netback | | | | | |
Oil and Natural Gas Sales | $ | 127,179 |
| | $ | 138,228 |
| $ | 94,659 |
| 46 |
|
Operating Expenses | (31,403 | ) | | (26,265 | ) | (23,937 | ) | 10 |
|
Transportation Expenses | (5,635 | ) | | (6,997 | ) | (6,942 | ) | 1 |
|
Operating Netback(3) | $ | 90,141 |
| | $ | 104,966 |
| $ | 63,780 |
| 65 |
|
| | | | | |
G&A Expenses Before Stock-Based Compensation, Gross | $ | 7,637 |
| | $ | 7,982 |
| $ | 7,563 |
| 6 |
|
G&A Stock-Based Compensation | 4,501 |
| | 3,178 |
| 1,149 |
| 177 |
|
General and Administrative ("G&A") Expenses, Including Stock-Based Compensation | $ | 12,138 |
| | $ | 11,160 |
| $ | 8,712 |
| 28 |
|
| | | | | |
EBITDA(3) | $ | 20,123 |
| | $ | 88,588 |
| $ | 61,255 |
| 45 |
|
| | | | | |
Adjusted EBITDA(3) | $ | 78,180 |
| | $ | 88,775 |
| $ | 55,020 |
| 61 |
|
| | | | | |
Funds Flow From Operations(3) | $ | 69,123 |
| | $ | 74,748 |
| $ | 45,026 |
| 66 |
|
| | | | |
|
|
Capital Expenditures | $ | 75,322 |
| | $ | 72,694 |
| $ | 46,160 |
| 57 |
|
|
| | | | | | | | |
| As at |
(Thousands of U.S. Dollars) | March 31, 2018 | December 31, 2017 | % Change |
Cash and Cash Equivalents | $ | 160,474 |
| $ | 12,326 |
| — |
|
| | | |
Revolving Credit Facility | $ | — |
| $ | 148,000 |
| (100 | ) |
| | | |
Senior Notes | $ | 300,000 |
| $ | — |
| — |
|
| | | |
Convertible Notes | $ | 115,000 |
| $ | 115,000 |
| — |
|
(2) Sales volumes represent production NAR adjusted for inventory changes.
(3) Non-GAAP measures
Operating netback, adjusted EBITDA, and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net 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 recovery or expense. Adjusted EBITDA is EBITDA adjusted for asset impairment, unrealized financial instruments loss or gain, loss on sale of business units and foreign exchange gains or losses. Management uses these supplemental 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 useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net loss to EBITDA and adjusted EBITDA is as follows:
|
| | | | | | | | | | |
| Three Months Ended December 31, | | Three Months Ended March 31, |
(Thousands of U.S. Dollars) | 2017 | | 2018 | 2017 |
Net income (loss) | $ | (40,802 | ) | | $ | 17,861 |
| $ | 12,771 |
|
Adjustments to reconcile net income (loss) to EBITDA and adjusted EBITDA | | | | |
DD&A expenses | 38,606 |
| | 39,461 |
| 26,593 |
|
Interest expense | 3,467 |
| | 5,495 |
| 3,095 |
|
Income tax expense | 18,852 |
| | 25,771 |
| 18,796 |
|
EBITDA (non-GAAP) | 20,123 |
| | 88,588 |
| 61,255 |
|
Asset impairment | 275 |
| | — |
| 283 |
|
Unrealized financial instruments loss (gain) | 21,185 |
| | 1,129 |
| (4,671 | ) |
Loss on sale of business units | 35,309 |
| | — |
| — |
|
Foreign exchange loss (gain)
| 1,288 |
| | (942 | ) | (1,847 | ) |
Adjusted EBITDA (non-GAAP) | $ | 78,180 |
| | $ | 88,775 |
| $ | 55,020 |
|
Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, asset impairment, deferred tax expense or recovery, 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 of business units. 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 December 31, | | Three Months Ended March 31, |
(Thousands of U.S. Dollars) | 2017 | | 2018 | 2017 |
Net income (loss) | $ | (40,802 | ) | | 17,861 |
| $ | 12,771 |
|
Adjustments to reconcile net income (loss) to funds flow from operations | | | | |
DD&A expenses | 38,606 |
| | 39,461 |
| 26,593 |
|
Asset impairment | 275 |
| | — |
| 283 |
|
Deferred tax expense | 8,052 |
| | 13,482 |
| 11,379 |
|
Stock-based compensation expense | 4,840 |
| | 3,309 |
| 1,203 |
|
Amortization of debt issuance costs | 547 |
| | 670 |
| 605 |
|
Cash settlement of RSUs | (30 | ) | | (120 | ) | (318 | ) |
Unrealized foreign exchange loss (gain) | 1,141 |
| | (1,044 | ) | (2,819 | ) |
Financial instruments loss (gain) | 21,140 |
| | 6,946 |
| (5,439 | ) |
Cash settlement of financial instruments | 45 |
| | (5,817 | ) | 768 |
|
Loss on sale of business units | 35,309 |
| | — |
| — |
|
Funds flow from operations (non-GAAP) | $ | 69,123 |
| | $ | 74,748 |
| $ | 45,026 |
|
Additional Operational Results
|
| | | | | | | | | | | | |
| Three Months Ended December 31, | | Three Months Ended March 31, |
| 2017 | | 2018 | 2017 | % Change |
(Thousands of U.S. Dollars) | | | | | |
Oil and natural gas sales | $ | 127,179 |
| | $ | 138,228 |
| $ | 94,659 |
| 46 |
|
Operating expenses | 31,403 |
| | 26,265 |
| 23,937 |
| 10 |
|
Transportation expenses | 5,635 |
| | 6,997 |
| 6,942 |
| 1 |
|
Operating netback(1) | 90,141 |
| | 104,966 |
| 63,780 |
| 65 |
|
| | | | | |
DD&A expenses | 38,606 |
| | 39,461 |
| 26,593 |
| 48 |
|
Asset impairment | 275 |
| | — |
| 283 |
| (100 | ) |
G&A expenses before stock-based compensation | 7,637 |
| | 7,982 |
| 7,563 |
| 6 |
|
G&A stock-based compensation expense | 4,501 |
| | 3,178 |
| 1,149 |
| 177 |
|
Severance expenses | 123 |
| | — |
| — |
| — |
|
Equity tax | — |
| | — |
| 1,224 |
| (100 | ) |
Foreign exchange loss (gain) | 1,288 |
| | (942 | ) | (1,847 | ) | 49 |
|
Financial instruments loss (gain) | 21,140 |
| | 6,946 |
| (5,439 | ) | 228 |
|
Interest expense | 3,467 |
| | 5,495 |
| 3,095 |
| 78 |
|
| 77,037 |
| | 62,120 |
| 32,621 |
| 90 |
|
| | | | | |
Loss on sale of business units | (35,309 | ) | | — |
| — |
| — |
|
Interest income | 255 |
| | 786 |
| 408 |
| 93 |
|
| | | | |
|
(Loss) income before income taxes | (21,950 | ) | | 43,632 |
| 31,567 |
| 38 |
|
| | | | | |
Current income tax expense | 10,800 |
| | 12,289 |
| 7,417 |
| 66 |
|
Deferred income tax expense | 8,052 |
| | 13,482 |
| 11,379 |
| 18 |
|
| 18,852 |
| | 25,771 |
| 18,796 |
| 37 |
|
Net income (loss) | $ | (40,802 | ) | | $ | 17,861 |
| $ | 12,771 |
| 40 |
|
| | | | |
|
Sales Volumes (NAR) | | | | |
|
Total sales volumes, BOEPD | 28,169 |
| | 27,203 |
| 24,808 |
| 10 |
|
| | | | |
|
Average Prices | | | | |
|
Oil and NGL's per bbl | $ | 49.37 |
| | $ | 56.63 |
| $ | 42.96 |
| 32 |
|
Natural gas per Mcf | $ | 1.88 |
| | $ | 2.91 |
| $ | 1.52 |
| 91 |
|
| | | | |
|
|
Brent Price per bbl | $ | 61.54 |
| | $ | 67.18 |
| $ | 54.66 |
| 23 |
|
| | | | | |
Consolidated Results of Operations per BOE Sales Volumes NAR | | | | |
|
|
Oil and natural gas sales | $ | 49.07 |
| | $ | 56.46 |
| $ | 42.40 |
| 33 |
|
Operating expenses | 12.12 |
| | 10.73 |
| 10.72 |
| — |
|
Transportation expenses | 2.17 |
| | 2.86 |
| 3.11 |
| (8 | ) |
Operating netback(1) | 34.78 |
| | 42.87 |
| 28.57 |
| 50 |
|
|
| | | | | | | | | | | | |
| | | | | |
DD&A expenses | 14.90 |
| | 16.12 |
| 11.91 |
| 35 |
|
Asset impairment | 0.11 |
| | — |
| 0.13 |
| (100 | ) |
G&A expenses before stock-based compensation | 2.95 |
| | 3.26 |
| 3.39 |
| (4 | ) |
G&A stock-based compensation expense | 1.74 |
| | 1.30 |
| 0.51 |
| 155 |
|
Severance expenses | 0.05 |
| | — |
| — |
| — |
|
Equity tax | — |
| | — |
| 0.55 |
| (100 | ) |
Foreign exchange loss (gain) | 0.50 |
| | (0.38 | ) | (0.83 | ) | 54 |
|
Financial instruments loss (gain) | 8.16 |
| | 2.84 |
| (2.44 | ) | 216 |
|
Interest expense | 1.34 |
| | 2.24 |
| 1.39 |
| 61 |
|
| 29.75 | | 25.38 | 14.61 | 74 |
|
| | | | | |
Loss on sale of business units | (13.62 | ) | | — |
| — |
| — |
|
Interest income | 0.10 |
| | 0.32 |
| 0.18 |
| 78 |
|
| | | | |
|
|
(Loss) income before income taxes | (8.49 | ) | | 17.81 |
| 14.14 |
| 26 |
|
Current income tax expense | 4.17 |
| | 5.02 |
| 3.32 |
| 51 |
|
Deferred income tax expense | 3.11 |
| | 5.51 |
| 5.10 |
| 8 |
|
| 7.28 |
| | 10.53 |
| 8.42 |
| 25 |
|
Net income (loss) | $ | (15.77 | ) | | $ | 7.28 |
| $ | 5.72 |
| 27 |
|
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operating Highlights—non-GAAP measures" for a definition and reconciliation of this measure.
Oil and Gas Production and Sales Volumes, BOEPD
|
| | | | | | | | | | | | | |
| Three Months Ended March 31, 2018 | | Three Months Ended March 31, 2017 |
Average Daily Volumes (BOEPD) | Colombia | Brazil | Total | | Colombia | Brazil | Total |
Working Interest Production Before Royalties | 35,075 |
| — |
| 35,075 |
| | 28,481 |
| 1,398 |
| 29,879 |
|
Royalties | (6,886 | ) | — |
| (6,886 | ) | | (4,868 | ) | (221 | ) | (5,089 | ) |
Production NAR | 28,189 |
| — |
| 28,189 |
| | 23,613 |
| 1,177 |
| 24,790 |
|
(Increase) Decrease in Inventory | (986 | ) | — |
| (986 | ) | | 7 |
| 11 |
| 18 |
|
Sales | 27,203 |
| — |
| 27,203 |
| | 23,620 |
| 1,188 |
| 24,808 |
|
| | | | | | | |
Royalties, % of Working Interest Production Before Royalties | 20 | % | — | % | 20 | % | | 17 | % | 16 | % | 17 | % |
Oil and gas production NAR for the three months ended March 31, 2018 increased by 14% to 28,189 BOEPD, compared with 24,790 BOEPD in the comparable period of 2017. Colombian NAR production for the three months ended March 31, 2018 increased 19% compared with the comparable period of 2017. We increased oil and gas production NAR as a result of successful drilling and a workover campaign in the Acordionero Field, the Vonu-1 exploration well and a workover campaign in the Cumplidor Field in Colombia. Working interest production before royalties from the Acordionero Field averaged 16,751 bopd before royalties during the three months ended March 31, 2018 compared with 6,198 bopd in the comparative period of 2017, a 170% increase.
Royalties as a percentage of production for the three months ended March 31, 2018 increased compared with the comparative period in the prior year commensurate with the increase in oil prices due to price sensitive royalties payable in Colombia, higher API in the Acordionero Field and Acordionero reaching the threshold for the High Price Royalties.
Operating Netbacks
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2018 | | Three Months Ended March 31, 2017 |
(Thousands of U.S. Dollars) | Colombia | Brazil | Total | | Colombia | Brazil | Total |
Oil and Natural Gas Sales | $ | 138,228 |
| $ | — |
| $ | 138,228 |
| | $ | 90,464 |
| $ | 4,195 |
| $ | 94,659 |
|
Transportation Expenses | (6,997 | ) | — |
| (6,997 | ) | | (6,765 | ) | (177 | ) | (6,942 | ) |
| 131,231 |
| — |
| 131,231 |
| | 83,699 |
| 4,018 |
| 87,717 |
|
Operating Expenses | (26,265 | ) | — |
| (26,265 | ) | | (23,156 | ) | (781 | ) | (23,937 | ) |
Operating Netback(1) | $ | 104,966 |
| $ | — |
| $ | 104,966 |
| | $ | 60,543 |
| $ | 3,237 |
| $ | 63,780 |
|
| | | | | | | |
U.S. Dollars Per BOE Sales Volumes NAR | | | | | | | |
Brent | $ | 67.18 |
| $ | — |
| $ | 67.18 |
| | $ | 54.66 |
| $ | 54.66 |
| $ | 54.66 |
|
Quality and Transportation Discounts | (10.72 | ) | — |
| (10.72 | ) | | (12.11 | ) | (15.42 | ) | (12.26 | ) |
Average Realized Price | 56.46 |
| — |
| 56.46 |
| | 42.55 |
| 39.24 |
| 42.40 |
|
Transportation Expenses | (2.86 | ) | — |
| (2.86 | ) | | (3.18 | ) | (1.66 | ) | (3.11 | ) |
Average Realized Price Net of Transportation Expenses | 53.60 |
| — |
| 53.60 |
| | 39.37 |
| 37.58 |
| 39.29 |
|
Operating Expenses | (10.73 | ) | — |
| (10.73 | ) | | (10.89 | ) | (7.31 | ) | (10.72 | ) |
Operating Netback(1) | $ | 42.87 |
| $ | — |
| $ | 42.87 |
| | $ | 28.48 |
| $ | 30.27 |
| $ | 28.57 |
|
(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, 2018, increased by 46% to $138.2 million from $94.7 million, in the comparable period of 2017 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 months ended March 31, 2018 compared with the prior quarter and the comparative period in 2017:
|
| | | | | | |
| First Quarter 2018 Compared with Fourth Quarter 2017 | First Quarter 2018 Compared with First Quarter 2017 |
Oil and natural gas sales for the comparative period | $ | 127,179 |
| $ | 94,659 |
|
Realized sales price increase effect | 18,078 |
| 34,426 |
|
Sales volume (decrease) increase effect | (7,029 | ) | 9,143 |
|
Oil and natural gas sales for period ended March 31, 2018 | $ | 138,228 |
| $ | 138,228 |
|
Average realized prices for the three months ended March 31, 2018, increased by 33% commensurate with the increase in benchmark oil prices and lower transportation and quality discounts compared with the comparable period of 2017. Average Brent oil prices for the three months ended March 31, 2018, increased by 23% compared with the comparable period of 2017.
Oil and gas sales for the three months ended March 31, 2018, increased by 9% to $138.2 million from $127.2 million compared with the prior quarter due to higher realized oil prices, partially offset by lower sales volumes. Lower sales volumes were the net result of higher working interest production before royalties being more than offset by an increase in inventory and higher price sensitive royalties as a result of increased Brent prices. Average realized prices increased by 15% to $56.46 per BOE for the three months ended March 31, 2018, compared with $49.07 per BOE in the prior quarter. Average Brent oil prices for the three months ended March 31, 2018, increased by 9% to $67.18 per bbl, compared with $61.54 per bbl in the prior quarter.
We have options to sell our oil though 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 months ended March 31, 2018 and 2017 and the prior quarter:
|
| | | | | | |
| Three Months Ended December 31, | Three Months Ended March 31, |
| 2017 | 2018 | 2017 |
Volume transported through pipeline | 10 | % | 9 | % | 25 | % |
Volume sold at wellhead | 47 | % | 52 | % | 50 | % |
Volume sold not at wellhead, trucking | 43 | % | 39 | % | 25 | % |
| 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 months ended March 31, 2018, increased by 1% to $7.0 million compared with the corresponding period in 2017. On a per BOE basis, transportation expenses decreased by 8% to $2.86 from $3.11 in the corresponding period in 2017.
Colombian transportation expenses for the three months ended March 31, 2018 on a per BOE basis, decreased by 10% to $2.86 per from $3.18 in the corresponding period in 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.
Total Company transportation expenses for the three months ended March 31, 2018 increased 24% to $7.0 million compared with $5.6 million in the prior quarter. On a per BOE basis, transportation expenses increased by 32% to $2.86 from $2.17 in the prior quarter. The increase was primarily due to the use of alternative transportation routes, which had higher costs per BOE.
The quarterly increase in Colombia transportation expenses was more than offset by a decrease in quality and transportation discounts. On a per BOE basis, quality and transportation discounts decreased by 14% to $10.72 from $12.47 in the prior quarter, a reduction which resulted from optimization of transportation routes and narrowing of differentials.
The following table shows the variance in our average realized prices net of transportation expenses in Colombia for the three months ended March 31, 2018 compared with the prior quarter and the comparative period in 2017:
|
| | | | | | |
U.S. Dollars Per BOE Sales Volumes NAR | First Quarter 2018 Compared with Fourth Quarter 2017 | First Quarter 2018 Compared with First Quarter 2017 |
Average realized price net of transportation expenses for the comparative period | $ | 46.90 |
| $ | 39.37 |
|
Increase in benchmark prices | 5.64 |
| $ | 12.52 |
|
Decrease in quality and transportation discounts | 1.75 |
| 1.39 |
|
(Increase) decrease in transportation expenses | (0.69 | ) | 0.32 |
|
Average realized price net of transportation expenses for the period ended March 31, 2018 | $ | 53.60 |
| $ | 53.60 |
|
Total Company operating expenses for the three months ended March 31, 2018 increased by 10% to $26.3 million compared with the corresponding period in 2017. The increase was due to higher sales volumes and the increased operating costs per BOE.
On a per BOE basis, Colombian operating expenses decreased by $0.16 and workover expenses decreased by $0.65 compared with the corresponding period in 2017. Excluding workover expenses, Colombia operating expenses increased by $0.49 per BOE primarily as a result of power disruption costs in the Putumayo region as a result of Mocoa natural disaster, the NaturAmazonas reforestation and conservation program and water injection activities conducted in the Acordionero Field during the first quarter of 2018.
Total Company operating expenses for the three months ended March 31, 2018 decreased by 16% to $26.3 million compared with the prior quarter. On a per BOE basis, operating expenses decreased by $1.39 to $10.73 for the three months ended March 31, 2018, from $12.12 in the prior quarter and workover expenses increased by $0.25. Excluding workover expenses, operating expenses decreased by $1.64 per BOE compared with the prior quarter primarily as a result of lower slickline testing service and maintenance activity in the quarter.
DD&A Expenses
|
| | | | | | | | | | | | | |
| Three Months Ended March 31, 2018 | | Three Months Ended March 31, 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 | $ | 38,499 |
| $ | 15.72 |
| | $ | 24,935 |
| $ | 11.73 |
|
Brazil | — |
| — |
| | 1,213 |
| 11.35 |
|
Peru | — |
| — |
| | 226 |
| — |
|
Corporate | 962 |
| — |
| | 219 |
| — |
|
| $ | 39,461 |
| $ | 16.12 |
| | $ | 26,593 |
| $ | 11.91 |
|
DD&A expenses for the three months ended March 31, 2018, increased to $39.5 million ($16.12 per BOE) from $26.6 million ($11.91 per BOE) in the comparable period 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 8% to $16.12 per BOE for the three months ended March 31, 2018, from $14.90 per BOE in the prior quarter due to higher costs in the depletable base.
G&A Expenses
|
| | | | | | | | | | | | |
| Three Months Ended December 31, | | Three Months Ended March 31, |
(Thousands of U.S. Dollars) | 2017 | | 2018 | 2017 | % Change |
G&A Expenses Before Stock-Based Compensation | $ | 7,637 |
| | $ | 7,982 |
| $ | 7,563 |
| 6 |
|
G&A Stock-Based Compensation | 4,501 |
| | 3,178 |
| 1,149 |
| 177 |
|
G&A Expenses, Including Stock-Based Compensation | $ | 12,138 |
| | $ | 11,160 |
| $ | 8,712 |
| 28 |
|
| | | | | |
U.S. Dollars Per BOE Sales Volumes NAR |
|
| |
|
|
|
|
|
|
G&A Expenses Before Stock-Based Compensation | $ | 2.95 |
| | $ | 3.26 |
| $ | 3.39 |
| (4 | ) |
G&A Stock-Based Compensation | 1.74 |
| | 1.30 |
| 0.51 |
| 155 |
|
G&A Expenses, Including Stock-Based Compensation | $ | 4.69 |
| | $ | 4.56 |
| $ | 3.90 |
| 17 |
|
G&A expenses for the three months ended March 31, 2018, decreased by 8% to $11.2 million compared with $12.1 million in the prior quarter primarily due to lower stock-based compensation.
For the three months ended March 31, 2018, G&A expenses before stock-based compensation increased by 6% from the corresponding period in 2017. The increase was commensurate with our growth and activity. On a per BOE basis, G&A expenses decreased 4% from the comparative period. After stock-based compensation, G&A expenses for the three months ended March 31, 2018 increased by 28% to $11.2 million from $8.7 million in the corresponding period in 2017. The increase was mainly due to the increase in G&A Stock-Based Compensation resulting from additional PSUs outstanding and higher share price at March 31, 2018.
Foreign Exchange Gains and Losses
For the three months ended March 31, 2018, we had foreign exchange gains of $0.9 million, compared to $1.8 million in the corresponding period in 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. The following table presents the change in the U.S. dollar against the Colombian peso for the three months ended March 31, 2018, and 2017:
|
| | |
| Three Months Ended March 31, |
| 2018 | 2017 |
Change in the U.S. dollar against the Colombian peso | weakened by | weakened by |
7% | 4% |
Financial Instrument Gains and Losses
The following table presents the nature of our financial instruments gains and losses for the three months ended March 31, 2018, and 2017:
|
| | | | | | |
| Three Months Ended March 31, |
(Thousands of U.S. Dollars) | 2018 | 2017 |
Commodity price derivative loss (gain) | $ | 4,995 |
| $ | (4,703 | ) |
Foreign currency derivatives gain | (3,970 | ) | (736 | ) |
Investment loss | 5,921 |
| — |
|
| $ | 6,946 |
| $ | (5,439 | ) |
Income Tax Expense and Recovery
|
| | | | | | |
| Three Months Ended March 31, |
(Thousands of U.S. Dollars) | 2018 | 2017 |
Income before income tax | $ | 43,632 |
| $ | 31,567 |
|
| | |
Current income tax expense | $ | 12,289 |
| $ | 7,417 |
|
Deferred income tax expense | 13,482 |
| 11,379 |
|
Total income tax expense | $ | 25,771 |
| $ | 18,796 |
|
| | |
Effective tax rate | 59 | % | 60 | % |
Current income tax expense was higher in the three months ended March 31, 2018, compared with the corresponding period in 2017 as a result of higher taxable income in Colombia. The deferred income tax expense of $13.5 million for the three months ended March 31, 2018, was primarily due to excess tax depreciation as compared with accounting depreciation in Colombia.
For the three months ended March 31, 2018, the difference between the effective tax rate of 59% and the 21% U.S. statutory rate was primarily due to an increase to the impact of foreign taxes, valuation allowance, other permanent differences, non-deductible third party royalty in Colombia, stock based compensation, other local taxes and foreign currency translation.
For the three months ended March 31, 2017, the difference between the effective tax rate of 60% and the 35% U.S. statutory rate was 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 taxes, local taxes, and stock based compensation. These items were partially offset by foreign currency translation adjustments and other permanent differences.
Net Income and Funds Flow from Operations (a Non-GAAP Measure)
|
| | | | | | | | | | |
(Thousands of U.S. Dollars) | First Quarter 2018 Compared with Fourth Quarter 2017 | % change | First Quarter 2018 Compared with First Quarter 2017 | % change |
Net income (loss) for the comparative period | $ | (40,802 | ) | | $ | 12,771 |
| |
Increase (decrease) due to: | | | | |
Prices | 18,078 |
| | 34,426 |
| |
Sales volumes | (7,029 | ) | | 9,143 |
| |
Expenses: | | | | |
Operating | 5,138 |
| | (2,328 | ) | |
Transportation | (1,362 | ) | | (55 | ) | |
Cash G&A and RSU settlements, excluding stock-based compensation expense | (643 | ) | | (144 | ) | |
Severance | 123 |
| | — |
| |
Interest, net of amortization of debt issuance costs | (1,905 | ) | | (2,335 | ) | |
Realized foreign exchange | 44 |
| | 869 |
| |
Settlement of financial instruments | (5,862 | ) | | (6,585 | ) | |
Current taxes | (1,489 | ) | | (4,872 | ) | |
Equity tax | — |
| | 1,224 |
| |
Other | 532 |
| | 379 |
| |
Net change in funds flow from operations(1) from comparative period | 5,625 |
| | 29,722 |
| |
Expenses: |
|
| | |
Depletion, depreciation and accretion | (855 | ) | | (12,868 | ) | |
Asset impairment | 275 |
| | 283 |
| |
Deferred tax | (5,430 | ) | | (2,103 | ) | |
Amortization of debt issuance costs | (123 | ) | | (65 | ) | |
Stock-based compensation, net of RSU settlement | 1,621 |
| | (2,3 |