UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q10-Q/A
AMENDMENT NO. 1
(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 September 30, 20172021
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 |
| Calgary, | Alberta | Canada | T2P 0R3 | |
(Address of principal executive offices, including zip code) |
(403) 265-3221
(Registrant’sRegistrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | |
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Common Stock, par value $0.001 per share | GTE | NYSE American |
Toronto Stock Exchange |
London Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 | ☐ | Accelerated filer | ☒ |
Non-accelerated filer | ☐ | Smaller reporting company | ☒ |
| |
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 companyo | ☐ |
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 October 31, 2017, the following number of29, 2021, 367,144,500 shares of the registrant’s capital stock were outstanding: 388,415,513 shares of the registrant’sregistrant's Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 1,688,889 shares of were issued.
EXPLANATORY NOTE
Gran Tierra GoldstrikeEnergy Inc., which are exchangeable (the “Company”) is filing this Amendment No. 1 (“Amendment”) to its Form 10-Q for the quarter ended September 30, 2021, originally filed with the Securities and Exchange Commission (“SEC”) on a 1-for-1 basis intoNovember 2, 2021 (the “Original 10-Q”). This Amendment is being filed solely for the registrant’s Common Stock;purpose of correcting an incorrect date in the certification by the Company's Chief Executive Officer and one shareChief Financial Officer pursuant to Section 906 of Special B Voting Stock, $0.001 par value, representing 4,666,792 sharesthe Sarbanes-Oxley Act of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into2002 filed as Exhibit 32.1 to the registrant’s Common Stock.Original 10-Q. In accordance with Compliance and Disclosure Interpretations published by the SEC Staff, the entire periodic report for the quarter ended September 30, 2021 is included in this Amendment. Other than the correction described above, no other statement or amount has been changed from those presented in the Original 10-Q.
Gran Tierra Energy Inc.
Quarterly Report on Form 10-Q
Quarterly Period Ended September 30, 20172021
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 6.2. | ExhibitsUnregistered Sales of Equity Securities and Use of Proceeds | |
SIGNATURESItem 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 impactand benefits of proposedthe changes in our capital program or pending transactions,expenditures, our liquidity, the impacts of the coronavirus (COVID-19) pandemic 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, our ability to comply with covenants in our credit agreement and indentures and make borrowings under our credit agreement; our ability to obtain amendments to the covenants in our credit agreement so as to avoid an event of default under our credit agreement and senior notes; a reduction in our borrowing base and our ability to repay any excess borrowings; sustained or future declines in commodity prices;prices and the demand for oil; sustained or future excess supply of oil and natural gas; potential future impairments and reductions in proved reserve quantities and value; continuation of the COVID-19 pandemic and responses thereto, including possible future restrictions against oil and gas activity in Colombia and Ecuador; our current operations are located in South America, and unexpected problems can arise due to guerilla activity;activity and other local conditions; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; geographic, political and weather conditions can impact the production, transport or sale of our products; the risk thatour ability to raise capital; our ability to identify and complete successful acquisitions, including in new countries and basins from our current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict;operations; our ability to execute its business plan; the risk thatplans; 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 and the regulatory environment may impact oil prices and oil consumption moredifferently than we currently predict, which could cause us to further modify our strategy and capital spending program; volatility or declines in the trading price of our common stock and the continued listing of our shares on a national stock exchange; and those factors set out in Part II, Item 1A "Risk Factors" in this Quarterly Report on Form 10-Q and Part I, Item 1A “Risk Factors” in our 20162020 Annual Report on Form 10-K (the "2020 Annual Report on Form 10-K"), and in our other filings with the Securities and Exchange Commission (“SEC”). The unprecedented nature of the COVID-19 pandemic and volatility in the worldwide economy and oil and gas industry makes, including the unpredictable nature of the resurgence of cases, possible variants and governmental responses, it more difficult to predict the accuracy of forward-looking statements. 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, or to withdraw, 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 |
MbblBOPD | 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.
PART I - Financial Information
Item 1. Financial Statements
Gran Tierra Energy Inc.
Condensed Consolidated Statements of Operations (Unaudited)
(Thousands of U.S. Dollars, Except Share and Per Share Amounts) | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
OIL SALES (Note 8) | $ | 135,319 | | | $ | 53,142 | | | $ | 327,435 | | | $ | 173,045 | |
| | | | | | | |
EXPENSES | | | | | | | |
Operating | 37,567 | | | 20,721 | | | 92,623 | | | 84,673 | |
Transportation | 3,021 | | | 1,286 | | | 8,448 | | | 8,549 | |
COVID-19 related costs (Note 9) | 990 | | | 1,108 | | | 3,026 | | | 1,529 | |
Depletion, depreciation and accretion | 38,055 | | | 31,340 | | | 98,300 | | | 131,118 | |
Goodwill impairment (Note 5) | — | | | — | | | — | | | 102,581 | |
Asset impairment (Note 5) | — | | | 104,731 | | | — | | | 507,093 | |
General and administrative | 6,497 | | | 4,562 | | | 25,072 | | | 16,476 | |
Severance | — | | | 122 | | | 919 | | | 1,469 | |
Foreign exchange loss | 2,650 | | | 4,275 | | | 15,824 | | | 20,094 | |
Derivative instruments loss (gain) (Note 12) | 2,603 | | | (2,173) | | | 47,540 | | | (9,417) | |
Other financial instruments (gain) loss (Note 12) | (13,634) | | | 1,460 | | | (12,425) | | | 61,286 | |
Other loss | — | | | 67 | | | — | | | 67 | |
Interest expense (Note 6) | 13,608 | | | 14,029 | | | 41,355 | | | 40,204 | |
| 91,357 | | | 181,528 | | | 320,682 | | | 965,722 | |
| | | | | | | |
INTEREST INCOME | — | | | — | | | — | | | 345 | |
INCOME (LOSS) BEFORE INCOME TAXES | 43,962 | | | (128,386) | | | 6,753 | | | (792,332) | |
| | | | | | | |
INCOME TAX EXPENSE (RECOVERY) | | | | | | | |
Current (Note 10) | — | | | 637 | | | (14) | | | 560 | |
Deferred (Note 10) | 8,955 | | | (21,202) | | | 26,809 | | | (62,796) | |
| 8,955 | | | (20,565) | | | 26,795 | | | (62,236) | |
NET AND COMPREHENSIVE INCOME (LOSS) | $ | 35,007 | | | $ | (107,821) | | | $ | (20,042) | | | $ | (730,096) | |
| | | | | | | |
NET INCOME (LOSS) PER SHARE | | | | | | | |
| | | | | | | |
BASIC AND DILUTED | $ | 0.10 | | | $ | (0.29) | | | $ | (0.05) | | | $ | (1.99) | |
| | | | | | | |
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 7) | 366,992,802 | | | 366,981,556 | | | 366,985,646 | | | 366,981,556 | |
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 7) | 367,740,722 | | | 366,981,556 | | | 366,985,646 | | | 366,981,556 | |
(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)
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| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
OIL AND NATURAL GAS SALES (NOTE 3) | $ | 103,768 |
| | $ | 68,539 |
| | $ | 294,555 |
| | $ | 197,655 |
|
|
|
| |
|
| |
|
| |
|
|
EXPENSES | | | | | | | |
Operating | 27,321 |
| | 25,638 |
| | 78,466 |
| | 62,453 |
|
Transportation | 6,038 |
| | 5,773 |
| | 19,472 |
| | 24,318 |
|
Depletion, depreciation and accretion (Note 3) | 34,492 |
| | 35,729 |
| | 92,729 |
| | 104,525 |
|
Asset impairment (Notes 3 and 4) | 787 |
| | 319,974 |
| | 1,239 |
| | 469,715 |
|
General and administrative (Note 3) | 8,651 |
| | 5,592 |
| | 26,876 |
| | 20,614 |
|
Severance | 1,164 |
| | — |
| | 1,164 |
| | 1,299 |
|
Transaction | — |
| | 6,088 |
| | — |
| | 7,325 |
|
Equity tax | — |
| | — |
| | 1,224 |
| | 3,053 |
|
Foreign exchange (gain) loss | (1,271 | ) | | (507 | ) | | 779 |
| | 1,059 |
|
Financial instruments loss (gain) (Note 10) | 1,675 |
| | 2,051 |
| | (5,211 | ) | | 1,824 |
|
Interest expense (Note 5) | 3,989 |
| | 5,122 |
| | 10,415 |
| | 7,842 |
|
| 82,846 |
| | 405,460 |
| | 227,153 |
| | 704,027 |
|
| | | | | | | |
LOSS ON SALE OF BRAZIL BUSINESS UNIT (NOTE 4) | — |
| | — |
| | (9,076 | ) | | — |
|
GAIN ON ACQUISITION | — |
| | — |
| | — |
|
| 11,712 |
|
INTEREST INCOME | 301 |
| | 730 |
| | 954 |
| | 1,928 |
|
INCOME (LOSS) BEFORE INCOME TAXES (NOTE 3) | 21,223 |
| | (336,191 | ) | | 59,280 |
| | (492,732 | ) |
| | | | | | | |
INCOME TAX EXPENSE (RECOVERY) | | | | | | | |
Current | 4,333 |
| | 3,879 |
| | 13,522 |
| | 11,680 |
|
Deferred | 13,760 |
| | (110,451 | ) | | 36,664 |
| | (166,202 | ) |
| 18,093 |
| | (106,572 | ) | | 50,186 |
| | (154,522 | ) |
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | $ | 3,130 |
| | $ | (229,619 | ) | | $ | 9,094 |
| | $ | (338,210 | ) |
| | | | | | | |
NET INCOME (LOSS) PER SHARE - BASIC AND DILUTED | $ | 0.01 |
| | $ | (0.71 | ) | | $ | 0.02 |
| | $ | (1.11 | ) |
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6) | 394,771,194 |
| | 321,725,379 |
| | 397,439,007 |
| | 304,098,944 |
|
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6) | 394,774,953 |
| | 321,725,379 |
| | 397,450,637 |
| | 304,098,944 |
|
| | | | | | | | | | | |
| As at September 30, 2021 | | As at December 31, 2020 |
| | | |
ASSETS | | | |
Current Assets | | | |
Cash and cash equivalents (Note 13) | $ | 16,600 | | | $ | 14,114 | |
| | | |
Accounts receivable | 26,431 | | | 8,044 | |
Investment (Note 12) | 44,116 | | | 48,323 | |
| | | |
| | | |
| | | |
Taxes receivable (Note 3) | 47,772 | | | 49,925 | |
Other current assets | 17,141 | | | 13,459 | |
Total Current Assets | 152,060 | | | 133,865 | |
| | | |
Oil and Gas Properties | | | |
Proved | 833,069 | | | 797,355 | |
Unproved | 158,483 | | | 161,763 | |
Total Oil and Gas Properties | 991,552 | | | 959,118 | |
Other capital assets | 3,085 | | | 5,364 | |
Total Property, Plant and Equipment (Note 4) | 994,637 | | | 964,482 | |
| | | |
Other Long-Term Assets | | | |
Deferred tax assets | 13,349 | | | 57,318 | |
Taxes receivable (Note 3) | 14,447 | | | 42,635 | |
Restricted cash and cash equivalents (Note 13) | 3,532 | | | 3,409 | |
Other | 3,233 | | | 16 | |
Total Other Long-Term Assets | 34,561 | | | 103,378 | |
Total Assets | $ | 1,181,258 | | | $ | 1,201,725 | |
| | | |
LIABILITIES AND SHAREHOLDERS' EQUITY | | | |
Current Liabilities | | | |
Accounts payable and accrued liabilities | $ | 114,785 | | | $ | 100,784 | |
Derivatives (Note 12) | 14,737 | | | 12,050 | |
Taxes payable (Note 3) | 5,938 | | | — | |
Equity compensation award liability (Note 7 and 12) | 2,132 | | | 805 | |
Total Current Liabilities | 137,592 | | | 113,639 | |
| | | |
Long-Term Liabilities | | | |
Long-term debt (Notes 6 and 12) | 735,411 | | | 774,770 | |
| | | |
Asset retirement obligation | 54,356 | | | 48,214 | |
Equity compensation award liability (Note 7 and 12) | 11,469 | | | 3,955 | |
Other long-term liabilities | 3,563 | | | 4,113 | |
Total Long-Term Liabilities | 804,799 | | | 831,052 | |
| | | |
Contingencies (Note 11) | 0 | | 0 |
| | | |
Shareholders' Equity | | | |
Common Stock (Note 7) (367,038,454 and 366,981,556 shares issued and outstanding of Common Stock, par value $0.001 per share, as at September 30, 2021, and December 31, 2020, respectively) | 10,270 | | | 10,270 | |
Additional paid-in capital | 1,286,893 | | | 1,285,018 | |
Deficit | (1,058,296) | | | (1,038,254) | |
Total Shareholders' Equity | 238,867 | | | 257,034 | |
Total Liabilities and Shareholders’ Equity | $ | 1,181,258 | | | $ | 1,201,725 | |
(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) |
| | | | | | | |
| September 30, | | December 31, |
| 2017 | | 2016 |
ASSETS | | | |
Current Assets | | | |
Cash and cash equivalents (Note 11) | $ | 15,125 |
| | $ | 25,175 |
|
Restricted cash and cash equivalents (Notes 7 and 11) | 3,920 |
| | 8,322 |
|
Accounts receivable | 38,279 |
| | 45,698 |
|
Derivatives (Note 10) | 512 |
| | 578 |
|
Inventory (Note 4) | 6,978 |
| | 7,766 |
|
Taxes receivable | 34,879 |
| | 26,393 |
|
Prepaid taxes (Note 2) | — |
| | 12,271 |
|
Other prepaids | 2,194 |
| | 5,482 |
|
Total Current Assets | 101,887 |
| | 131,685 |
|
| | | |
Oil and Gas Properties (using the full cost method of accounting) | |
| | |
|
Proved | 508,981 |
| | 412,319 |
|
Unproved | 613,419 |
| | 647,774 |
|
Total Oil and Gas Properties | 1,122,400 |
| | 1,060,093 |
|
Other capital assets | 5,224 |
| | 6,516 |
|
Total Property, Plant and Equipment (Notes 3 and 4) | 1,127,624 |
| | 1,066,609 |
|
| | | |
Other Long-Term Assets | |
| | |
|
Deferred tax assets (Note 2) | 66,963 |
| | 1,611 |
|
Prepaid taxes (Note 2) | — |
| | 41,784 |
|
Restricted cash and cash equivalents (Notes 7 and 11) | 10,332 |
| | 9,770 |
|
Other long-term assets | 13,789 |
| | 13,856 |
|
Goodwill (Note 3) | 102,581 |
| | 102,581 |
|
Total Other Long-Term Assets | 193,665 |
| | 169,602 |
|
Total Assets (Note 3) | $ | 1,423,176 |
| | $ | 1,367,896 |
|
LIABILITIES AND SHAREHOLDERS’ EQUITY | |
| | |
|
Current Liabilities | |
| | |
|
Accounts payable and accrued liabilities | $ | 119,829 |
| | $ | 107,051 |
|
Derivatives (Note 10) | 65 |
| | 3,824 |
|
Taxes payable (Note 2) | 2,419 |
| | 38,939 |
|
Asset retirement obligation (Note 7) | 355 |
| | 5,215 |
|
Total Current Liabilities | 122,668 |
| | 155,029 |
|
| | | |
Long-Term Liabilities | |
| | |
|
Long-term debt (Notes 5 and 10) | 229,215 |
| | 197,083 |
|
Deferred tax liabilities (Note 2) | 29,368 |
| | 107,230 |
|
Asset retirement obligation (Note 7) | 43,649 |
| | 38,142 |
|
Other long-term liabilities | 13,816 |
| | 11,425 |
|
Total Long-Term Liabilities | 316,048 |
| | 353,880 |
|
| | | |
Contingencies (Note 9) |
|
| |
|
|
| | | |
Shareholders’ Equity | |
| | |
|
Common Stock (Note 6) (386,872,530 and 390,807,194 shares of Common Stock and 7,898,664 and 8,199,894 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2017, and December 31, 2016, respectively) | 10,299 |
| | 10,303 |
|
Additional paid in capital | 1,334,563 |
| | 1,342,656 |
|
Deficit | (360,402 | ) | | (493,972 | ) |
Total Shareholders’ Equity | 984,460 |
| | 858,987 |
|
Total Liabilities and Shareholders’ Equity | $ | 1,423,176 |
| | $ | 1,367,896 |
|
(See notes to the condensed consolidated financial statements)
Gran Tierra Energy Inc.
Condensed Consolidated Statements of Cash Flows (Unaudited)
(Thousands of U.S. Dollars)
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Operating Activities | | | |
Net income (loss) | $ | 9,094 |
| | $ | (338,210 | ) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | |
|
Depletion, depreciation and accretion (Note 3) | 92,729 |
| | 104,525 |
|
Asset impairment (Notes 3 and 4) | 1,239 |
| | 469,715 |
|
Deferred tax expense (recovery) | 36,664 |
| | (166,202 | ) |
Stock-based compensation (Note 6) | 4,935 |
| | 4,380 |
|
Amortization of debt issuance costs (Note 5) | 1,868 |
| | 2,813 |
|
Cash settlement of restricted share units | (534 | ) | | (1,210 | ) |
Unrealized foreign exchange (gain) loss | (304 | ) | | 2,437 |
|
Financial instruments (gain) loss (Note 10) | (5,211 | ) | | 1,824 |
|
Cash settlement of financial instruments (Note 10) | 1,518 |
| | 438 |
|
Cash settlement of asset retirement obligation (Note 7) | (462 | ) | | (496 | ) |
Loss on sale of Brazil business unit (Note 4) | 9,076 |
| | — |
|
Gain on acquisition | — |
| | (11,712 | ) |
Net change in assets and liabilities from operating activities (Note 11) | (28,105 | ) | | 18,097 |
|
Net cash provided by operating activities | 122,507 |
| | 86,399 |
|
| | | |
Investing Activities | |
| | |
|
Additions to property, plant and equipment (Note 3) | (175,719 | ) | | (69,667 | ) |
Additions to property, plant and equipment - property acquisitions (Note 4) | (30,410 | ) | | (19,388 | ) |
Net proceeds from sale of Brazil business unit (Note 4) | 34,481 |
| | — |
|
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit (Note 4) | 4,700 |
| | — |
|
Cash paid for business combinations, net of cash acquired | — |
| | (457,183 | ) |
Proceeds from sale of marketable securities | — |
| | 788 |
|
Changes in non-cash investing working capital | 11,347 |
| | (8,036 | ) |
Net cash used in investing activities | (155,601 | ) | | (553,486 | ) |
| | | |
Financing Activities | |
| | |
|
Proceeds from bank debt, net of issuance costs (Note 5) | 115,264 |
| | 220,169 |
|
Repayment of bank debt (Note 5) | (85,000 | ) | | (110,181 | ) |
Proceeds from issuance of shares of Common Stock, net of issuance costs | — |
| | 5,169 |
|
Repurchase of shares of Common Stock (Note 6) | (10,000 | ) | | — |
|
Proceeds from issuance of subscription receipts, net of issuance costs | — |
| | 165,805 |
|
Proceeds from issuance of Convertible Senior Notes, net of issuance costs (Note 5) | — |
| | 109,090 |
|
Net cash provided by financing activities | 20,264 |
| | 390,052 |
|
| | | |
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents | (1,060 | ) | | (452 | ) |
| | | |
Net decrease in cash, cash equivalents and restricted cash and cash equivalents | (13,890 | ) | | (77,487 | ) |
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) | $ | 29,377 |
| | $ | 71,264 |
|
| | | |
Supplemental cash flow disclosures (Note 11) | |
| | |
|
(See notes to the condensed consolidated financial statements)
Gran Tierra Energy Inc.
Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)
(Thousands of U.S. Dollars)
|
| | | | | | | |
| Nine Months Ended September 30, | | Year Ended December 31, |
| 2017 | | 2016 |
Share Capital | | | |
Balance, beginning of period | $ | 10,303 |
| | $ | 10,186 |
|
Issuance of Common Stock | — |
| | 117 |
|
Repurchase of Common Stock (Note 6) | (4 | ) | | — |
|
Balance, end of period | 10,299 |
| | 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 | — |
| | 314,425 |
|
Exercise of stock options | — |
| | 5,347 |
|
Stock-based compensation (Note 6) | 1,903 |
| | 3,021 |
|
Repurchase of Common Stock (Note 6) | (9,996 | ) | | — |
|
Balance, end of period | 1,334,563 |
| | 1,342,656 |
|
| | | |
Deficit | |
| | |
|
Balance, beginning of period | (493,972 | ) | | (28,407 | ) |
Net income (loss) | 9,094 |
| | (465,565 | ) |
Cumulative adjustment for accounting change related to tax reorganizations (Note 2) | 124,476 |
| | — |
|
Balance, end of period | (360,402 | ) | | (493,972 | ) |
| | | |
Total Shareholders’ Equity | $ | 984,460 |
| | $ | 858,987 |
|
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2021 | | 2020 |
Operating Activities | | | |
Net loss | $ | (20,042) | | | $ | (730,096) | |
Adjustments to reconcile net loss to net cash provided by operating activities: | | | |
Depletion, depreciation and accretion | 98,300 | | | 131,118 | |
Goodwill impairment (Note 5) | — | | | 102,581 | |
Asset impairment (Note 5) | — | | | 507,093 | |
Deferred tax expense (recovery) | 26,809 | | | (62,796) | |
Stock-based compensation expense (recovery) (Note 7) | 6,597 | | | (707) | |
Amortization of debt issuance costs (Note 6) | 2,682 | | | 2,774 | |
Unrealized foreign exchange loss | 16,945 | | | 22,335 | |
Derivative instruments loss (gain) (Note 12) | 47,540 | | | (9,417) | |
Cash settlements on derivatives instruments | (45,041) | | | 9,970 | |
Other financial instruments (gain) loss (Note 12) | (12,425) | | | 61,286 | |
Other non-cash loss | — | | | 2,026 | |
Cash settlement of asset retirement obligation | (483) | | | (199) | |
Non-cash lease expenses | 1,222 | | | 1,494 | |
Lease payments | (1,239) | | | (1,404) | |
Net change in assets and liabilities from operating activities (Note 13) | 17,956 | | | 23,288 | |
Net cash provided by operating activities | 138,821 | | | 59,346 | |
| | | |
Investing Activities | | | |
Additions to property, plant and equipment | (109,650) | | | (56,378) | |
Proceeds on disposition of investment, net of transaction costs (Note 12) | 14,632 | | | — | |
Changes in non-cash investing working capital (Note 13) | 709 | | | (69,549) | |
Net cash used in investing activities | (94,309) | | | (125,927) | |
| | | |
Financing Activities | | | |
Proceeds from debt, net of issuance costs (Note 6) | (125) | | | 88,382 | |
Repayment of debt (Note 6) | (40,000) | | | (7,000) | |
| | | |
Proceeds from exercise of stock options | 19 | | | — | |
Lease payments | (1,269) | | | (307) | |
Net cash (used in) provided by financing activities | (41,375) | | | 81,075 | |
| | | |
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents | (528) | | | (754) | |
| | | |
Net increase in cash, cash equivalents and restricted cash and cash equivalents | 2,609 | | | 13,740 | |
Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 13) | 17,523 | | | 11,075 | |
Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 13) | $ | 20,132 | | | $ | 24,815 | |
| | | |
Supplemental cash flow disclosures (Note 13) | | | |
(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 September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Share Capital | | | | | | | |
Balance, beginning of period | $ | 10,270 | | | $ | 10,270 | | | $ | 10,270 | | | $ | 10,270 | |
| | | | | | | |
Balance, end of period | 10,270 | | | 10,270 | | | 10,270 | | | 10,270 | |
| | | | | | | |
Additional Paid-in Capital | | | | | | | |
Balance, beginning of period | 1,286,235 | | | 1,283,798 | | | 1,285,018 | | | 1,282,627 | |
| | | | | | | |
Exercise of stock options | 10 | | | — | | | 18 | | | — | |
| | | | | | | |
Stock-based compensation (Note 7) | 648 | | | 607 | | | 1,857 | | | 1,778 | |
Balance, end of period | 1,286,893 | | | 1,284,405 | | | 1,286,893 | | | 1,284,405 | |
| | | | | | | |
Deficit | | | | | | | |
Balance, beginning of period | (1,093,303) | | | (882,562) | | | (1,038,254) | | | (260,287) | |
Net income (loss) | 35,007 | | | (107,821) | | | (20,042) | | | (730,096) | |
Balance, end of period | (1,058,296) | | | (990,383) | | | (1,058,296) | | | (990,383) | |
| | | | | | | |
Total Shareholders' Equity | $ | 238,867 | | | $ | 304,292 | | | $ | 238,867 | | | $ | 304,292 | |
(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”"Company" or “Gran Tierra”"Gran Tierra"), is a publicly traded company focused on international oil and natural gas exploration and production with assets currently in Colombia. The Company also has business activities in PeruColombia and until June 30, 2017, had business activities in Brazil.Ecuador.
2. Significant Accounting Policies
These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”("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’sCompany's consolidated financial statements as at and for the year ended December 31, 2016,2020, included in the Company’s 2016Company's 2020 Annual Report on Form 10-K, filed with the SEC on March 1, 2017.10-K.
The Company’sCompany's significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2016Company's 2020 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements, except as noted below.statements. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.
Recently Adopted Accounting Pronouncements
3. Taxes Receivable and Payable
Simplifying the Measurement of Inventory
In July 2015, the Financial Accounting Standards Board (“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 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 Accounting Standards Codification ("ASC") 740 "Income Taxes", 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. Early adoption was permitted. The Company early adopted this ASU on January 1, 2017, 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. For the nine months ended September 30, 2016, the net decrease in cash, cash equivalents and restricted cash and cash equivalents currently disclosed was $77.5 million, compared with the net decrease in cash and cash equivalents of $97.3 million as previously disclosed in the consolidated statement of cash flows prior to the adoption of ASU 2016-18.
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. The Company’s acquisition of the Santana and Nancy Burdine-Maxine oil and gas properties in the nine months ended September 30, 2017 was not considered a business under this ASU and therefore not allocated goodwill or gain on acquisition (Note 4).
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. 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 September 30, 2017, 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.
Recently Issued Accounting Pronouncements
Revenue from Contracts with Customers
In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers - Deferral of the Effective Date". The ASU deferred the effective date of the new revenue recognition model by one year. As a result, the guidance will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. In March 2016, the FASB issued ASU 2016-08,
“Principal versus Agent Considerations (Reporting Revenue Gross versus Net)" which clarifies implementation guidance on principal versus agent considerations. In April, May and December 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing", ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients" and ASU 2016-20 "Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers", respectively, which addressed implementation issues and provided technical corrections. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings.
The Company is continuing to evaluatetable below shows the impactbreak-down of the ASUtaxes receivable and currently expects that the standard will not have a material impact on the Company’s consolidated financial statements other than enhanced disclosures related to revenues from contracts with customers. The Company intends to adopt the new standard using the modified retrospective method at the datepayable, which are comprised of adoption, which is expected to be January 1, 2018.value added tax ("VAT") and income tax:
| | | | | | | | | | | |
(Thousands of U.S. Dollars) | As at September 30, 2021 | | As at December 31, 2020 |
Taxes Receivable | | | |
Current | | | |
VAT Receivable | $ | 31,890 | | | $ | 35,977 | |
Income Tax Receivable | 15,882 | | | 13,948 | |
| $ | 47,772 | | | $ | 49,925 | |
Long-Term | | | |
VAT Receivable | $ | — | | | $ | 28,485 | |
Income Tax Receivable | 14,447 | | | 14,150 | |
| $ | 14,447 | | | $ | 42,635 | |
| | | |
Taxes Payable | | | |
Current | | | |
VAT Payable | $ | 5,938 | | | $ | — | |
| | | |
Total Taxes Receivable net of Taxes Payable | $ | 56,281 | | | $ | 92,560 | |
| | | |
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 and Peru, based on geographic organization. Prior to the sale of the Company’s Brazil business unit effective June 30, 2017, (Note 4), Brazil was a reportable segment. The All Other category represents the Company’s corporate and Mexico activities. The Company evaluates reportable segment performance based on income or loss before income taxes.
The following tables present informationtable shows the movement of VAT and income tax receivables for the period identified below:
| | | | | | | | | | | | | | | | | |
(Thousands of U.S. Dollars) | Net VAT Receivable | | Income Tax Receivable | | Total Net Taxes Receivable |
Balance, as at December 31, 2020 | $ | 64,462 | | | $ | 28,098 | | | $ | 92,560 | |
Collected through direct government refunds | (518) | | | (14,228) | | | (14,746) | |
Collected through sales contracts | (70,881) | | | — | | | (70,881) | |
Taxes paid (1) | 38,278 | | | 19,923 | | | 58,201 | |
| | | | | |
Foreign exchange loss | (5,389) | | | (3,464) | | | (8,853) | |
Balance, as at September 30, 2021 | $ | 25,952 | | | $ | 30,329 | | | $ | 56,281 | |
(1)VAT is paid on the Company’s reportable segmentscertain goods and other activities:services in Colombia at a rate of 19%
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 |
(Thousands of U.S. Dollars) | Colombia | | Peru | | Brazil | | All Other | | Total |
Oil and natural gas sales | $ | 103,768 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 103,768 |
|
Depletion, depreciation and accretion | 33,388 |
| | 881 |
| | — |
| | 223 |
| | 34,492 |
|
Asset impairment | — |
| | 176 |
| | — |
| | 611 |
| | 787 |
|
General and administrative expenses | 5,500 |
| | 301 |
| | — |
| | 2,850 |
| | 8,651 |
|
Income (loss) before income taxes | 31,276 |
| | (1,405 | ) | | — |
| | (8,648 | ) | | 21,223 |
|
Segment capital expenditures | 70,606 |
| | 998 |
| | — |
| | 90 |
| | 71,694 |
|
| | | | | | | | | |
| Three Months Ended September 30, 2016 |
(Thousands of U.S. Dollars) | Colombia | | Peru | | Brazil | | All Other | | Total |
Oil and natural gas sales | $ | 65,944 |
| | $ | — |
| | $ | 2,595 |
| | $ | — |
| | $ | 68,539 |
|
Depletion, depreciation and accretion | 34,156 |
| | 206 |
| | 1,022 |
| | 345 |
| | 35,729 |
|
Asset impairment | 298,370 |
| | — |
| | 21,604 |
| | — |
| | 319,974 |
|
General and administrative expenses | 1,921 |
| | 218 |
| | 218 |
| | 3,235 |
| | 5,592 |
|
Loss before income taxes | (299,306 | ) | | (768 | ) | | (20,977 | ) | | (15,140 | ) | | (336,191 | ) |
Segment capital expenditures | 20,476 |
| | 1,360 |
| | 3,102 |
| | 142 |
| | 25,080 |
|
| | | | | | | | | |
| Nine Months Ended September 30, 2017 |
(Thousands of U.S. Dollars) | Colombia | | Peru | | Brazil | | All Other | | Total |
Oil and natural gas sales | $ | 286,137 |
| | $ | — |
| | $ | 8,418 |
| | $ | — |
| | $ | 294,555 |
|
Depletion, depreciation and accretion | 88,453 |
| | 1,350 |
| | 2,263 |
| | 663 |
| | 92,729 |
|
Asset impairment | — |
| | 628 |
| | — |
| | 611 |
| | 1,239 |
|
General and administrative expenses | 15,561 |
| | 974 |
| | 743 |
| | 9,598 |
| | 26,876 |
|
Income (loss) before income taxes | 90,018 |
| | (2,685 | ) | | 3,369 |
| | (31,422 | ) | | 59,280 |
|
Segment capital expenditures | 168,881 |
| | 3,207 |
| | 2,811 |
| | 820 |
| | 175,719 |
|
| | | | | | | | | |
| Nine Months Ended September 30, 2016 |
(Thousands of U.S. Dollars) | Colombia | | Peru | | Brazil | | All Other | | Total |
Oil and natural gas sales | $ | 191,515 |
| | $ | — |
| | $ | 6,140 |
| | $ | — |
| | $ | 197,655 |
|
Depletion, depreciation and accretion | 100,350 |
| | 418 |
| | 2,764 |
| | 993 |
| | 104,525 |
|
Asset impairment | 431,810 |
| | 899 |
| | 37,006 |
| | — |
| | 469,715 |
|
General and administrative expenses | 9,614 |
| | 1,014 |
| | 751 |
| | 9,235 |
| | 20,614 |
|
Loss before income taxes | (436,863 | ) | | (2,224 | ) | | (36,523 | ) | | (17,122 | ) | | (492,732 | ) |
Segment capital expenditures | 56,997 |
| | 3,730 |
| | 7,982 |
| | 958 |
| | 69,667 |
|
|
| | | | | | | | | | | | | | | | | | | |
| As at September 30, 2017 |
(Thousands of U.S. Dollars) | Colombia | | Peru | | Brazil | | All Other | | Total |
Property, plant and equipment | $ | 1,054,136 |
| | $ | 70,903 |
| | $ | — |
| | $ | 2,585 |
| | $ | 1,127,624 |
|
Goodwill | 102,581 |
| | — |
| | — |
| | — |
| | 102,581 |
|
All other assets | 176,672 |
| | 11,103 |
| | — |
| | 5,196 |
| | 192,971 |
|
Total Assets | $ | 1,333,389 |
| | $ | 82,006 |
| | $ | — |
| | $ | 7,781 |
| | $ | 1,423,176 |
|
| | | | | | | | | |
| 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 |
|
4. Property, Plant and Equipment
| | | | | | | | | | | |
(Thousands of U.S. Dollars) | As at September 30, 2021 | | As at December 31, 2020 |
Oil and natural gas properties | | | |
Proved | $ | 4,236,548 | | | $ | 4,106,768 | |
Unproved | 158,483 | | | 161,763 | |
| 4,395,031 | | | 4,268,531 | |
Other(1) | 32,779 | | | 32,135 | |
| 4,427,810 | | | 4,300,666 | |
Accumulated depletion and depreciation and impairment | (3,433,173) | | | (3,336,184) | |
| $ | 994,637 | | | $ | 964,482 | |
(1) The "other" category includes right-of-use assets for operating and Inventoryfinance leases of $11.7 million, which had a net book value of $2.5 million as at September 30, 2021 (December 31, 2020 - $11.4 million which had a net book value of $4.4 million).
Property, Plant and Equipment
5. Impairment
|
| | | | | | | |
(Thousands of U.S. Dollars) | As at September 30, 2017 | | As at December 31, 2016 |
Oil and natural gas properties | | | |
|
Proved | $ | 2,836,263 |
| | $ | 2,652,171 |
|
Unproved | 613,419 |
| | 647,774 |
|
| 3,449,682 |
| | 3,299,945 |
|
Other | 27,236 |
| | 29,445 |
|
| 3,476,918 |
| | 3,329,390 |
|
Accumulated depletion, depreciation and impairment | (2,349,294 | ) | | (2,262,781 | ) |
| $ | 1,127,624 |
| | $ | 1,066,609 |
|
Asset impairment for
(i) Oil and gas property impairment
For the three and nine months ended September 30, 2017, and 2016 was as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2016 | | 2017 | | 2016 |
Impairment of oil and gas properties | $ | 787 |
| | $ | 319,974 |
| | $ | 1,239 |
| | $ | 469,051 |
|
Impairment of inventory | — |
| | — |
| | — |
| | 664 |
|
| $ | 787 |
| | $ | 319,974 |
| | $ | 1,239 |
| | $ | 469,715 |
|
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, adjusted for 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 this estimate 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 $52.70 per bbl for the purposes of the September 30, 2017 ceiling test calculations (June 30, 2017 - $51.35; March 31, 2017 - $49.33; December 31, 2016 - $42.92; September 30, 2016 - $42.23; June 30, 2016 - $44.48; March 31, 2016 - $48.79; December 31, 2015 - $54.08).
Acquisition of Santana and Nancy Burdine-Maxine Blocks
On April 27, 2017, the Company acquired the Santana and Nancy-Burdine-Maxine Blocks in the Putumayo Basin for cash consideration of $30.4 million. The acquisition was accounted for as an asset acquisition with the consideration paid allocated on a relative fair value basis to the net assets acquired.
The following table shows the allocation of the cost of the acquisition based on the relative fair values of the assets and
liabilities acquired:
|
| | | |
(Thousands of U.S. Dollars) | |
Cost of asset acquisition: | |
Cash | $ | 30,410 |
|
| |
Allocation of Consideration Paid: | |
Oil and gas properties | |
Proved | $ | 24,405 |
|
Unproved | 8,649 |
|
| 33,054 |
|
Inventory | 869 |
|
Asset retirement obligation - long-term | (3,513 | ) |
| $ | 30,410 |
|
Disposition of Brazil Business Unit
On June 30, 2017, the Company, through two of its indirect subsidiaries (the “Selling Subsidiaries”), completed the previously announced disposition of its assets in Brazil. Gran Tierra completed the disposition of its Brazil business unit for a purchase price of $35.0 million which, after certain interim closing adjustments, resulted in cash consideration paid to the Selling Subsidiaries of approximately $38.0 million.
At December 31, 2016, assets and liabilities of the Brazil business unit were as follows:
|
| | | |
(Thousands of U.S. Dollars) | As at December 31, 2016 |
Current assets | $ | 1,634 |
|
Property, plant and equipment | 55,376 |
|
| $ | 57,010 |
|
| |
Current liabilities | $ | (11,590 | ) |
Long-term liabilities | (2,297 | ) |
| $ | (13,887 | ) |
At June 30, 2017, the net book value of the Brazil business unit was greater than the proceeds received resulting in a $9.1 million loss on sale.
Gran Tierra also received a $4.7 million cash payment from the purchaser reflecting the covenant by the purchaser to finalize the documentation and other arrangements to assume liabilities associated with letter of credit arrangements and the release of Gran Tierra from any liabilities in connection with the same, which payment will be reimbursable to the purchaser once such covenant is discharged.
Inventory
At September 30, 2017, oil and supplies inventories were $4.5 million and $2.5 million, respectively (December 31, 2016 - $6.0 million and $1.8 million, respectively). At September 30, 2017,2021, the Company had 168 Mbbl of oil inventory (December 31, 2016 - 208 Mbbl). Inno ceiling test impairment losses. For each of the three and nine months ended September 30, 2017,2020, Gran Tierra had $104.7 million and $502.9 million of ceiling test impairment losses. The Company used an average Brent price of $60.12 and $47.95 per bbl for the Company recorded oil inventorySeptember 30, 2021 and 2020, ceiling test calculations, respectively.
(ii) Inventory impairment of $nil (three
For the three and nine months ended September 30, 2016 - $nil and $0.7 million, respectively) related to lower oil prices.
5. Debt and Interest Expense
At September 30, 2017,2021, the Company had a revolving credit facility with a syndicateno inventory impairment. For the three and nine months ended September 30, 2020, the Company recorded $0.1 million and $4.2 million, respectively, of lenders with a borrowing baseinventory impairment.
Goodwill impairment
The entire goodwill balance of $300 million. Availability under$102.6 million was impaired during the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. As a result of the semi-annual redetermination, the committed borrowing base was increased from $250 million to $300 million effective June 1, 2017. The next re-determination of the borrowing base isnine months ended September 30, 2020, due to occur no later than November 2017. On September 18, 2017, the Company entered into the Eighth Amendmentreporting unit's carrying value exceeding its fair value due to the credit agreement with the other parties thereto, which, among other things, extended the maturity dateimpact of the borrowings under the revolving credit facility from September 18, 2018, to October 1, 2018.lower forecasted commodity prices.
6. Debt and Debt Issuance Costs
The Company's debt at September 30, 2017,2021, and December 31, 2016,2020, was as follows:
| | (Thousands of U.S. Dollars) | As at September 30, 2017 | | As at December 31, 2016 | (Thousands of U.S. Dollars) | As at September 30, 2021 | | As at December 31, 2020 |
Convertible senior notes | $ | 115,000 |
| | $ | 115,000 |
| |
6.25% Senior Notes, due February 2025 | | 6.25% Senior Notes, due February 2025 | $ | 300,000 | | | $ | 300,000 | |
7.75% Senior Notes, due May 2027 | | 7.75% Senior Notes, due May 2027 | 300,000 | | | 300,000 | |
Revolving credit facility | 120,000 |
| | 90,000 |
| Revolving credit facility | 150,000 | | | 190,000 | |
Unamortized debt issuance costs | (5,785 | ) | | (7,917 | ) | Unamortized debt issuance costs | (15,566) | | | (18,124) | |
Long-term debt | $ | 229,215 |
| | $ | 197,083 |
| Long-term debt | 734,434 | | | 771,876 | |
Long-term lease obligation(1) | | Long-term lease obligation(1) | 977 | | | 2,894 | |
| | | $ | 735,411 | | | $ | 774,770 | |
(1) The current portion of the lease obligation has been included in accounts payable and accrued liabilities on the Company's balance sheet and totaled $2.9 million as at September 30, 2021 (December 31, 2020 - $3.3 million).
As at September 30, 2021, the borrowing base of the Company's Senior Secured Credit Facility (the "revolving credit facility") was $215 million. The maturity date of the revolving credit facility is October 2022 and the next re-determination to occur no later than November 2021.
The Company is required to comply with various covenants, which were modified in response to market conditions including the COVID-19 pandemic until October 1, 2021 ("the covenant relief period"). During the covenant relief period, the Company's ratio of total debt to Covenant EBITDAX ("EBITDAX") was permitted to be greater than 4.0 to 1.0, Senior Secured Debt to EBITDAX ratio could not exceed 2.5 to 1.0, and EBITDAX to interest expense ratio for the trailing four-quarter periods measured as of the last day of the fiscal quarter ended September 30, 2021, was required to be 2.0 to 1.0. As of September 30, 2021, the Company was in compliance with all applicable covenants in the revolving credit facility.
Commencing on October 1, 2021, the Company must maintain compliance with the following financial covenants: limitations on Company's ratio of debt to EBITDAX to a maximum of 4.0 to 1.0; limitations on Company's ratio of Senior Secured Debt to EBITDAX to a maximum of 3.0 to 1.0; and the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. If the Company fails to comply with these financial covenants, it would result in a default under the terms of the credit agreement, which could result in an acceleration of repayment of all indebtedness under the Company's revolving credit facility.
Amounts drawn down under the revolving credit facility bear interest, at the Company's option, at the USD LIBOR rate plus a
margin ranging from 2.90% to 4.90%, or an alternate base rate plus a margin ranging from 1.90% to 3.90%, in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. We pay a commitment fee on undrawn amounts under the revolving credit facility, which ranges from 0.73% to 1.23% per annum, based on the average daily amount of unused commitments.
The Company's revolving credit facility is guaranteed by and secured against the assets of certain of the Company's subsidiaries (the "Credit Facility Group"). Under the terms of the revolving credit facility, the Company is subject to certain restrictions on its ability to distribute funds to entities outside of the Credit Facility Group, including restrictions on the ability to pay dividends to shareholders of the Company.
Interest Expense
The following table presents total interest expense recognized in the accompanying interim unaudited condensed consolidated statements of operations:
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | | 2020 | | 2021 | 2020 |
Contractual interest and other financing expenses | $ | 12,701 | | | $ | 13,191 | | | $ | 38,673 | | $ | 37,430 | |
Amortization of debt issuance costs | 907 | | | 838 | | | 2,682 | | 2,774 | |
| $ | 13,608 | | | $ | 14,029 | | | $ | 41,355 | | $ | 40,204 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2016 | | 2017 | | 2016 |
Contractual interest and other financing expenses | $ | 3,346 |
| | $ | 2,938 |
| | $ | 8,547 |
| | $ | 5,029 |
|
Amortization of debt issuance costs | 643 |
| | 2,184 |
| | 1,868 |
| | 2,813 |
|
| $ | 3,989 |
| | $ | 5,122 |
| | $ | 10,415 |
| | $ | 7,842 |
|
6.7. Share Capital
| | | | | |
| Shares of Common Stock |
Balance, December 31, 2020 | 366,981,556 | |
Shares issued on option exercise | 56,898 | |
Balance, September 30, 2021 | 367,038,454 | |
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 $0.001 per share.
|
| | | | | | |
| Shares of Common Stock | Exchangeable Shares of Gran Tierra Exchangeco Inc. | Exchangeable Shares of Gran Tierra Goldstrike Inc. |
Balance, December 31, 2016 | 390,807,194 |
| 4,812,592 |
| 3,387,302 |
|
Shares repurchased and canceled | (4,235,890 | ) | — |
| — |
|
Exchange of exchangeable shares | 301,230 |
| (142,500 | ) | (158,730 | ) |
Shares canceled | (4 | ) | — |
| — |
|
Balance, September 30, 2017 | 386,872,530 |
| 4,670,092 |
| 3,228,572 |
|
On February 6, 2017, the Company announced that it had implemented a new share repurchase program (the “2017 Program”) through the facilities of the Toronto Stock Exchange ("TSX"), the NYSE American and eligible alternative trading platforms in Canada and the United States. Under the 2017 Program, the Company is able to purchase at prevailing market prices up to 19,540,359 shares of Common Stock, representing 5.0% of the issued and outstanding shares of Common Stock as of January 27, 2017. Shares purchased pursuant to the 2017 Program will be canceled. The 2017 Program will expire on February 7, 2018, or earlier if the 5.0% share maximum is reached.
Equity Compensation Awards
The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock option activity for the nine months ended September 30, 2017:2021:
| | | | | | | | | | | | | | | | | |
| PSUs | DSUs | | Stock Options |
| Number of Outstanding Share Units | Number of Outstanding Share Units | | Number of Outstanding Stock Options | Weighted Average Exercise Price/Stock Option ($) |
Balance, December 31, 2020 | 23,273,404 | | 4,067,897 | | | 15,444,949 | | 1.50 | |
Granted | 13,428,840 | | 1,310,122 | | | 5,834,014 | | 0.80 | |
Exercised | (2,733,209) | | — | | | (56,898) | | 0.33 | |
Forfeited | (3,492,165) | | — | | | (1,628,591) | | 0.90 | |
Expired | — | | — | | | (1,279,641) | | 3.17 | |
Balance, September 30, 2021 | 30,476,870 | | 5,378,019 | | | 18,313,833 | | 1.22 | |
|
| | | | | | | | | | | |
| 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 | 3,229,620 |
| 171,388 |
| — |
| | 1,964,156 |
| 2.54 |
|
Exercised | — |
| — |
| (211,022 | ) | | — |
| — |
|
Forfeited | (641,159 | ) | — |
| (9,402 | ) | | (903,910 | ) | (4.81 | ) |
Expired | — |
| — |
| — |
| | (1,396,667 | ) | (4.65 | ) |
Balance, September 30, 2017 | 5,951,178 |
| 380,086 |
| 138,721 |
| | 8,903,057 |
| 3.66 |
|
Stock-based compensation expense forFor the three and nine months ended September 30, 2017,2021, stock-based compensation expense was $1.8$1.1 million and $4.9$6.6 million, respectively and was primarily recorded in general and administrative ("G&A") expenses (three and nine months ended September 30, 2016 - $0.92020, expense of $0.1 million and $4.4recovery of $0.7 million, respectively).
At September 30, 2017,2021, there was $11.5$14.2 million (December (December 31, 20162020 - $10.0$5.9 million) of unrecognized compensation costcosts related to unvested PSUs RSUs and stock options, which is expected to be recognized over a weighted averageweighted-average period of 1.71.8 years. During the nine months ended September 30, 2021, the Company paid out $0.6 million for PSUs vested on December 31, 2020 (nine months ended September 30, 2020 - $3.2 million for PSUs vested on December 31, 2019).
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 sharescommon stock issued and outstanding during each period.
Diluted net income (loss) per share is calculated by adjustingusing the treasury stock method for share-based compensation arrangements. The treasury stock method assumes that any proceeds obtained on the exercise of share-based compensation arrangements would be used to purchase common shares at the average market price during the period. The weighted average number of shares of Common Stock and exchangeable shares outstanding foris then adjusted by the dilutive effect, if any, of share equivalents. The Company usesdifference between 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 pricenumber of shares issued from the exercise of Common Stock duringshare-based compensation arrangements and shares repurchased from the period.related proceeds. Anti-dilutive shares represent potentially dilutive securities excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.
Weighted Average Shares Outstanding
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | 2020 |
Weighted average number of common shares outstanding | 366,992,802 | | 366,981,556 | | | 366,985,646 | | 366,981,556 | |
Shares issuable pursuant to stock options | 1,574,305 | | — | | | — | | — | |
Shares assumed to be purchased from proceeds of stock options | (826,385) | | — | | | — | | — | |
Weighted average number of diluted common shares outstanding | 367,740,722 | | 366,981,556 | | | 366,985,646 | | 366,981,556 | |
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
Weighted average number of common and exchangeable shares outstanding | 394,771,194 |
| | 321,725,379 |
| | 397,439,007 |
| | 304,098,944 |
|
Shares issuable pursuant to stock options | 61,325 |
| | — |
| | 187,150 |
| | — |
|
Shares assumed to be purchased from proceeds of stock options | (57,566 | ) | | — |
| | (175,520 | ) | | — |
|
Weighted average number of diluted common and exchangeable shares outstanding | 394,774,953 |
| | 321,725,379 |
| | 397,450,637 |
| | 304,098,944 |
|
For the three months ended September 30, 2017, 9,259,8112021, 16,362,882 options, on a weighted average basis (three months ended September 30, 20162020 - 9,084,162all options), were excluded from the diluted income (loss) per share calculation as the options were anti-dilutive. For the nine months ended September 30, 2017, 9,744,7472021 and 2020, all options on a weighted average basis (nine months ended September 30, 2016 - 11,155,962 options) were excluded from the diluted income (loss)loss per share calculation as the options were anti-dilutive. Shares issuable
8. Revenue
The Company's revenues are generated from oil sales at prices that reflect the blended prices received upon conversionshipment by the purchaser at defined sales points or defined by contract relative to ICE Brent and adjusted for Vasconia or Castilla crude differentials, quality, and transportation discounts each month. For the three and nine months ended September 30, 2021, 100% (three and nine months ended September 30, 2020 - 100%) of the 5.00% Convertible Senior Notes dueCompany's revenue resulted from oil sales. During the three and nine months ended September 30, 2021, ("Notes")quality and transportation discounts were anti-dilutive16% and excluded from15%, respectively, of the diluted income (loss) per share calculation.average ICE Brent price (three and nine months ended September 30, 2020 - 22% and 27%, respectively). During the three and nine months ended September 30, 2021, the Company's production was sold primarily to two major customers in Colombia (three and nine months ended September 30, 2020 - two).
7. Asset Retirement ObligationAs at September 30, 2021, accounts receivable included NaN of accrued sales revenue related to September 2021 production (December 31, 2020 - $0.1 million related to December 2020 production).
Changes
9. COVID-19 Costs
The COVID-19 pandemic has resulted in additional ongoing operating and transportation costs related to COVID-19 health and safety preventative measures, including incremental sanitation requirements and enhanced procedures for trucking barrels and crew changes in the carrying amountsfield. Below is a break-down of the asset retirement obligation associated withcosts:
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | 2020 | | 2021 | | 2020 |
Operating expenses | $ | 881 | | $ | 1,012 | | | $ | 2,743 | | | $ | 1,433 | |
Transportation costs | 109 | | 96 | | | 283 | | | 96 | |
Total COVID-19 costs | $ | 990 | | $ | 1,108 | | | $ | 3,026 | | | $ | 1,529 | |
10. Taxes
The Company's effective tax rate was 397% for the Company’s oilnine months ended September 30, 2021, compared to 8% in the comparative period of 2020. Current income tax was in a recovery position for the nine months ended September 30, 2021, versus an expense position for the comparative period in 2020, primarily as a result of changes in the previous estimation of presumptive minimum tax. The deferred income tax expense for the nine months ended September 30, 2021, resulted from excess tax depreciation compared to accounting depreciation and natural gas properties were as follows:the use of tax losses to offset taxable income in Colombia. The deferred income tax recovery in the comparative period of 2020 was mainly the result of a ceiling test impairment loss in Colombia, partially offset by losses incurred in Colombia that are now fully offset by a valuation allowance.
|
| | | | | | | |
| Nine Months Ended | | Year Ended |
(Thousands of U.S. Dollars) | September 30, 2017 | | December 31, 2016 |
Balance, beginning of period | $ | 43,357 |
| | $ | 33,224 |
|
Liability incurred | 2,942 |
| | 2,606 |
|
Liabilities assumed in acquisition | 3,513 |
| | 15,723 |
|
Accretion | 3,101 |
| | 2,789 |
|
Settlements | (1,039 | ) | | (872 | ) |
Liabilities associated with assets sold | (2,200 | ) | | (3,257 | ) |
Revisions in estimated liability | (5,670 | ) | | (6,856 | ) |
Balance, end of period | $ | 44,004 |
| | $ | 43,357 |
|
| | | |
Asset retirement obligation - current | $ | 355 |
| | $ | 5,215 |
|
Asset retirement obligation - long-term | 43,649 |
| | 38,142 |
|
| $ | 44,004 |
| | $ | 43,357 |
|
For the nine months ended September 30, 2017, settlements included $0.5 million cash payments with2021, the balance in accounts payable and accrued liabilities at September 30, 2017. Revisions in estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives anddifference between the expected timing of settling asset retirement obligations. At September 30, 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 of 397% and the 31% Colombian tax rate was 85%primarily due to the non-deductibility of derivative instrument losses and financing costs; foreign currency translation adjustments, and stock based compensation. These were partially offset by a decrease in the valuation allowance and the non-taxable portion (50%) of the unrealized gain on PetroTal Corp. ("PetroTal") shares.
In the third quarter of 2021, Congressional authorities in Colombia enacted a new tax legislation, which includes an increase to the corporate income tax rate to 35% from 31%, effective January 1, 2022. Accordingly, the tax rates applied to the calculation of deferred income taxes, before valuation allowance, have been adjusted to reflect this change.
For the nine months ended September 30, 2017, compared with 31% in2020, the corresponding period in 2016. The Company'sdifference between the effective tax rate differed fromof 8% and the U.S. statutory32% Colombian tax rate of 35%was primarily due to
impact of foreign taxes, an increase in the valuation allowance, the non-deductibility of goodwill impairment for tax purposes, foreign translation adjustments and the non-deductible third-party royalty in Colombia, stock-based compensation and other local taxes. These items were partially offset by foreign currency translation adjustments. portion (50%) of the unrealized loss on PetroTal Corp. ("PetroTal") shares.
9.11. Contingencies
TheLegal Proceedings
Gran Tierra has a number of lawsuits and claims pending, including a dispute with 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 eligiblerelating 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 $49.8 million as at September 30, 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, the Company has a number of other lawsuits and claims pending.high price share royalties. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, the CompanyGran 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 associated with these lawsuits and claims as they are incurred or become probable and determinable.
Letters of credit and other credit support
At September 30, 2017,2021, the Company had provided letters of credit and other credit support totaling $74.5$102.4 million (December 31, 20162020 - $96.8$100.6 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts and other capital or operating requirements.
10.12. Financial Instruments and Fair Value Measurement
Financial Instruments
At September 30, 2017,2021, the Company’s financial instruments recognized inon the balance sheet consist of:consisted of cash and cash equivalents;equivalents, restricted cash and cash equivalents;equivalents, accounts receivable; derivatives,receivable, investment, other long-term assets, accounts payable and accrued liabilities, derivatives, equity compensation award liability, 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 investment, derivatives, and RSU and PSU liabilities are beingequity compensation award liability is remeasured atto the estimated fair value at the end of each reporting period.
Investment in PetroTal
The estimated fair value of the Company's investment in PetroTal was $44.1 million at September 30, 2021 ($48.3 million at December 31, 2020), based on the closing stock price of PetroTal of $0.41 CAD ($0.25 CAD at December 31, 2020) and the foreign exchange rate at that date. During the nine months ended September 30, 2021, the Company sold 44% (109 million common shares) of its interest in PetroTal for cash proceeds net of transaction costs of $14.6 million, resulting in a loss on sale of $5.1 million. PetroTal is a publicly-traded energy company incorporated and domiciled in Canada engaged in exploration, appraisal, and development of crude oil and natural gas in Peru. PetroTal's shares are listed on the Toronto Stock Exchange Venture under the trading symbol 'TAL' and on the London Stock Exchange Alternative Investment Market under the trading symbol 'PTAL'. As at September 30, 2021, Gran Tierra holds approximately 137 million common shares representing approximately 17% of PetroTal's issued and outstanding common shares.
Commodity and Foreign Currency Derivatives
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.
PSUs and DSUs
The estimated fair value of the RSUPSUs liability was estimatedis based on quoted market prices in an active market. The fair value of the PSU liability was estimated based ona pricing model using inputs such as quoted market prices in an active market and an option pricing model such as the Monte Carlo simulation option-pricing models.
PSUs performance factor. The fair value of DSUs liability is measured using quoted market prices in an active market.
The fair value of investment, derivatives, and RSU, PSUPSUs and DSU liabilitiesDSUs liability at September 30, 2017,2021, and December 31, 2016, were2020, was as follows:
| | | | | | | | | | | |
(Thousands of U.S. Dollars) | As at September 30, 2021 | | As at December 31, 2020 |
Investment | $ | 44,116 | | | $ | 48,323 | |
| | | |
| | | |
| | | |
Derivative liability | $ | 14,737 | | | $ | 12,050 | |
PSUs and DSUs liability | 13,601 | | | 4,760 | |
| $ | 28,338 | | | $ | 16,810 | |
|
| | | | | | | |
(Thousands of U.S. Dollars) | As at September 30, 2017 | | As at December 31, 2016 |
Foreign currency derivative asset | $ | 512 |
| | $ | 578 |
|
| | | |
Commodity price derivative liability | $ | 65 |
| | $ | 3,824 |
|
RSU, PSU and DSU liability | 6,851 |
| | 3,907 |
|
| $ | 6,916 |
| | $ | 7,731 |
|
The following table presents gains or losses on derivatives and other financial instruments recognized in the accompanying interim unaudited condensed consolidated statements of operations:
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | 2020 | | 2021 | 2020 |
Commodity price derivatives loss (gain) | $ | 2,586 | | $ | (2,206) | | | $ | 47,435 | | $ | (12,983) | |
Foreign currency derivatives loss | 17 | | 33 | | | 105 | | 3,566 | |
Derivative instruments loss (gain) | $ | 2,603 | | $ | (2,173) | | | $ | 47,540 | | $ | (9,417) | |
| | | | | |
Unrealized PetroTal investment (gain) loss | $ | (13,616) | | $ | 1,055 | | | $ | (17,477) | | $ | 60,124 | |
Loss on sale of PetroTal shares | — | | — | | | 5,070 | | — | |
Financial instruments (gain) loss | (18) | | 405 | | | (18) | | 1,162 | |
Other financial instruments (gain) loss | $ | (13,634) | | $ | 1,460 | | | $ | (12,425) | | $ | 61,286 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2016 | | 2017 | | 2016 |
Commodity price derivative loss (gain) | $ | 2,489 |
| | $ | 2,190 |
| | $ | (3,759 | ) | | $ | 856 |
|
Foreign currency derivatives gain | (814 | ) | | (840 | ) | | (1,452 | ) | | (1,958 | ) |
Trading securities loss | — |
| | 701 |
| | — |
| | 2,926 |
|
Financial instruments loss (gain) | $ | 1,675 |
| | $ | 2,051 |
| | $ | (5,211 | ) | | $ | 1,824 |
|
These gains and losses are presented as financial instrument gains and losses in the interim unaudited condensed consolidated statements of operations and cash flows.
Financial instruments not recorded at fair value include the Notes.Company's 6.25% Senior Notes due 2025 (the "6.25% Senior Notes") and 7.75% Senior Notes due 2027 (the "7.75% Senior Notes"). At September 30, 2017,2021, the carrying amountamounts of the 6.25% Senior Notes was $110.7and the 7.75% Senior Notes were $293.5 million and $291.7 million, respectively, which representsrepresented the aggregate principal amount less unamortized debt issuance costs, and the fair value was $121.9 million.values were $262.6 million and $260.1 million, respectively. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities.
At September 30, 2017,2021, the fair value of the derivativesinvestment and DSUs liability was determined using Level 1 inputs. The fair value of the derivative and PSUs liability 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 endperiod-end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s Senior Notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure above regarding the fair value of the Company’s revolving credit facility was determined using an income approach using Level 3 inputs. The disclosure 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 and Senior Notes was based on Level 1 inputs, and the fair value of credit facility was based on Level 2 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 orderflows to assure it can execute at least a portion of its planned capital spending.
At September 30, 2017,2021, the Company had outstanding commodity price derivative positions as follows:
| | | | | | | | | | | | | | | | | | | | |
Period and type of instrument | Volume, bopd | Reference | Sold Put ($/bbl, Weighted Average) | Purchased Put ($/bbl, Weighted Average) | Sold Call ($/bbl, Weighted Average) | Swap Price ($/bbl, Weighted Average) |
Three-way Collars: October 1, to December 31, 2021 | 7,000 | | ICE Brent | 47.14 | | 57.14 | | 68.95 | | n/a |
Swaps: October 1, to December 31, 2021 | 3,000 | | ICE Brent | n/a | n/a | n/a | 56.75 | |
|
| | | | | | | | | | | | |
Period and type of instrument | Volume, bopd | Reference | Sold Put ($/bbl) | Purchased Put ($/bbl) | Sold Call ($/bbl) |
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 |
|
Subsequent to September 30, 2017, the Company entered into the following commodity price contracts:
|
| | | | | | | | | |
Period and type of instrument | Volume, bopd | Reference | Purchased Swap ($/bbl) | Purchased Call ($/bbl) |
Swap: January 1, to December 31, 2018 | 2,500 |
| ICE Brent | $ | 55.75 |
|
|
Swap: January 1, to December 31, 2018 | 2,500 |
| ICE Brent | $ | 56.05 |
| |
Participating Swap: January 1, to December 31, 2018 | 2,500 |
| ICE Brent | $ | 50.00 |
| $ | 54.10 |
|
Foreign Currency Derivatives
The Company utilizes foreign currency derivatives to manage the variability in cash flows associated with the Company's forecasted Colombian peso ("COP") denominated expenses. At September 30, 2017,2021, the Company had outstanding foreign currency derivative positions as follows:
| | | | | | | | | | | | | | | | | |
Period and type of instrument | Amount Hedged (Millions of COP) | U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1) | Reference | Floor Price (COP, Weighted Average) | Cap Price (COP, Weighted Average) |
Collars: October 1, to December 31, 2021 | 3,000 | | 782 | | COP | 3,500 | | 3,630 | |
|
| | | | | | | | | |
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: October 1, 2017 to October 31, 2017 | 23,000 |
| 7,832 |
| COP | 3,000 |
| 3,117 |
|
Collar: November 1, 2017 to November 30, 2017 | 25,000 |
| 8,513 |
| COP | 3,000 |
| 3,139 |
|
Collar: December 1, 2017 to December 28, 2017 | 25,000 |
| 8,513 |
| COP | 3,000 |
| 3,142 |
|
| 73,000 |
| 24,858 |
| | | |
(1)At September 30, 20172021 foreign exchange rate.
Subsequent to September 30, 2017, the Company entered into the following foreign currency contracts:
|
| | | | | | | | | |
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: January 1, 2018 to December 31, 2018 | 132,000 |
| 44,949 |
| COP | 3,000 |
| 3,112 |
|
(1) At September 30, 2017 foreign exchange rate.
11.13. Supplemental Cash Flow Information
The following table provides a reconciliation of cash and cash equivalents and restricted cash and cash equivalents with the Company's interim unaudited condensed consolidated balance sheet thatshown as a sum to the total of the same suchthese amounts shown in the interim unaudited condensed consolidated statements of cash flows:
| | | | | | | | | | | | | | | | | |
(Thousands of U.S. Dollars) | As at September 30, | | As at December 31, |
| 2021 | 2020 | | 2020 | 2019 |
Cash and cash equivalents | $ | 16,600 | | $ | 21,808 | | | $ | 14,114 | | $ | 8,817 | |
| | | | | |
Restricted cash and cash equivalents - long-term | 3,532 | | 3,007 | | | 3,409 | | 2,258 | |
| $ | 20,132 | | $ | 24,815 | | | $ | 17,523 | | $ | 11,075 | |
|
| | | | | | | | | | | | | |
(Thousands of U.S. Dollars) | As at September 30, | | As at December 31, |
| 2017 | 2016 | | 2016 | 2015 |
Cash and cash equivalents | $ | 15,125 |
| $ | 48,073 |
| | $ | 25,175 |
| $ | 145,342 |
|
Restricted cash and cash equivalents - current | 3,920 |
| 13,198 |
| | 8,322 |
| 92 |
|
Restricted cash and cash equivalents - long-term | 10,332 |
| 9,993 |
| | 9,770 |
| 3,317 |
|
| $ | 29,377 |
| $ | 71,264 |
| | $ | 43,267 |
| $ | 148,751 |
|
Net changes in assets and liabilities from operating activities were as follows:
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2016 | (Thousands of U.S. Dollars) | 2021 | | 2020 |
Accounts receivable and other long-term assets | $ | 8,356 |
| | $ | 15,233 |
| Accounts receivable and other long-term assets | $ | (18,582) | | | $ | 31,108 | |
Derivatives | — |
| | (4,563 | ) | Derivatives | (2,427) | | | 694 | |
Inventory | (28 | ) | | 3,630 |
| Inventory | (2,920) | | | (2,377) | |
Prepaids | 3,080 |
| | 1,864 |
| Prepaids | 42 | | | (183) | |
Accounts payable and accrued and other long-term liabilities | 5,951 |
| | (11,297 | ) | Accounts payable and accrued and other long-term liabilities | 14,417 | | | (57,621) | |
Taxes receivable and payable | (45,464 | ) | | 13,230 |
| Taxes receivable and payable | 27,426 | | | 51,667 | |
Net changes in assets and liabilities from operating activities | $ | (28,105 | ) | | $ | 18,097 |
| Net changes in assets and liabilities from operating activities | $ | 17,956 | | | $ | 23,288 | |
Changes in non-cash investing working capital for the nine months ended September 30, 2021, are comprised of an increase in accounts payable and accrued liabilities of $0.6 million and a decrease in accounts receivable of $0.1 million (nine months ended September 30, 2020, a decrease in accounts payable and accrued liabilities of $69.9 million and a decrease in accounts receivable of $0.3 million).
The following table provides additional supplemental cash flow disclosures:
| | | | | | | | | | | |
| Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | | 2020 |
Cash paid for income taxes | $ | 20,433 | | | $ | 11,603 | |
Cash paid for interest | $ | 37,259 | | | $ | 35,408 | |
| | | |
Non-cash investing activities: | | | |
Net liabilities related to property, plant and equipment, end of period | $ | 29,420 | | | $ | 7,805 | |
|
| | | | | | | |
| Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2016 |
Non-cash investing activities: | | | |
Net liabilities related to property, plant and equipment, end of period | $ | 68,018 |
| | $ | 27,520 |
|
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 87 and 7,8, respectively, of our 2020 Annual Report on Form 10-K, filed with the SEC on March 1, 2017.10-K. Please see the cautionary language at the beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements and the risk factors described in Part II, Item 1A "Risk Factors" of this Quarterly Report on Form 10-Q, as well as Part I, Item 1A “Risk Factors” in our 20162020 Annual Report on Form 10-K.
Financial and Operational Highlights
Key Highlights for the third quarter of 2021
•Net income in the third quarter of 2021 was $35.0 million or $0.10 per share basic and diluted, compared with a net loss of $107.8 million or $(0.29) per share basic and diluted in the third quarter of 2020
•Income before income taxes in the third quarter of 2021 was $44.0 million compared to loss before income taxes of $128.4 million in the third quarter of 2020
•During the third quarter of 2021, we repaid $25.0 million of the amount drawn under the revolving credit facility
•Funds flow from operations(2) increased by 758% to $69.1 million compared to the third quarter of 2020 and increased 197% from the second quarter of 2021
•During the third quarter the Company generated $34.3 million of free cash flow(2) which was used for debt reduction
•Our third quarter of 2021 average production NAR was 23,372 BOPD (sales volumes - 23,833 BOPD), a 37% increase (sales volumes - 40% increase) from 17,051 BOPD (sales volumes - 17,066 BOPD) in the third quarter of 2020, and 23% increase (sales volumes - 29% increase) from the second quarter of 2021 which was impacted by national blockades in Colombia affecting production from major fields
•Oil sales were $135.3 million, 155% higher compared to $53.1 million in the third quarter of 2020 as a result of an increase in Brent price, offset by higher quality and transportation discounts. Oil sales increased by 40% compared with $96.6 million in the second quarter of 2021 as a result of a 6% increase in Brent price and a 29% increase in sales volumes
•Operating expenses increased 30% on a per bbl basis ($3.93 per bbl) compared to the third quarter of 2020 due to higher power generation costs in Acordionero and increased by 13% on a per bbl basis ($1.99 per bbl) compared to the second quarter of 2021 due to power generation and chemical costs
•Transportation expenses increased by 135% compared to the third quarter of 2020 as a result of the national blockades resulting in utilization of more expensive transportation routes and increased 3% compared to the second quarter of 2021
•Operating netback(2) increased by 204% and 39%, respectively, to $94.7 million compared to $31.1 million in the third quarter of 2020 and $68.3 million in the second quarter of 2021
•Adjusted EBITDA(2) increased by 274% and 125%, respectively, to $81.8 million compared to $21.9 million in the third quarter of 2020 and $36.3 million in the second quarter of 2021
•Quality and transportation discounts for the third quarter of 2021 increased to $11.51 per bbl compared to $9.49 per bbl in the third quarter of 2020 as a result of higher differentials and remained consistent when compared to $11.54 per bbl in the second quarter of 2021
•General and administrative expenses ("G&A") before stock-based compensation increased by 21% compared to the third quarter of 2020, consistent with the increase of operating activities in the current period. When compared to the second quarter of 2021, G&A before stock-based compensation decreased by 24% due to the timing of certain costs incurred and expensed in the prior quarter
•Capital additions for the third quarter of 2021 were $34.8 million, an increase of $27.5 million compared to the third quarter of 2020 and decreased slightly from the $37.4 million incurred in the second quarter of 2021
| | (Thousands of U.S. Dollars, unless otherwise indicated) | Three Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | (Thousands of U.S. Dollars, unless otherwise indicated) | Three Months Ended September 30, | | Three Months Ended June 30, | | Nine Months Ended September 30, |
| 2017 | | 2017 | 2016 | % Change | | 2017 | 2016 | % Change | | 2021 | 2020 | % Change | | 2021 | | 2021 | 2020 | % Change |
Average Daily Volumes (BOEPD) | | | | | | | | |
| Average Daily Volumes (BOPD) | | Average Daily Volumes (BOPD) | |
Consolidated | | | | | | | | Consolidated | |
Working Interest Production Before Royalties | 31,437 |
| | 32,570 |
| 25,835 |
| 26 |
| | 31,305 |
| 25,730 |
| 22 |
| |
Working Interest ("WI") Production Before Royalties | | Working Interest ("WI") Production Before Royalties | 28,957 | | 18,944 | | 53 | | | 23,035 | | | 25,501 | | 22,864 | | 12 | |
Royalties | (5,014 | ) | | (5,055 | ) | (3,855 | ) | 31 |
| | (5,052 | ) | (3,576 | ) | 41 |
| Royalties | (5,585) | | (1,893) | | 195 | | | (4,059) | | | (4,531) | | (2,600) | | 74 | |
Production NAR | 26,423 |
| | 27,515 |
| 21,980 |
| 25 |
| | 26,253 |
| 22,154 |
| 19 |
| Production NAR | 23,372 | | 17,051 | | 37 | | | 18,976 | | | 20,970 | | 20,264 | | 3 | |
(Increase) Decrease in Inventory | (140 | ) | | (68 | ) | (495 | ) | (86 | ) | | (64 | ) | 951 |
| (107 | ) | |
Sales(1) | 26,283 |
|
| 27,447 |
| 21,485 |
| 28 |
| | 26,189 |
| 23,105 |
| 13 |
| |
| | | | | | |
|
| |
Colombia | | | | | | | | |
Working Interest Production Before Royalties | 30,098 |
| | 32,570 |
| 24,874 |
| 31 |
| | 30,398 |
| 24,859 |
| 22 |
| |
Royalties | (4,819 | ) | | (5,055 | ) | (3,717 | ) | 36 |
| | (4,914 | ) | (3,439 | ) | 43 |
| |
Production NAR | 25,279 |
| | 27,515 |
| 21,157 |
| 30 |
| | 25,484 |
| 21,420 |
| 19 |
| |
(Increase) Decrease in Inventory | (147 | ) | | (68 | ) | (497 | ) | (86 | ) | | (70 | ) | 949 |
| (107 | ) | |
Decrease (Increase) in Inventory | | Decrease (Increase) in Inventory | 461 | | 15 | | 2,973 | | | (522) | | | (105) | | 117 | | (190) | |
Sales(1) | 25,132 |
| | 27,447 |
| 20,660 |
| 33 |
| | 25,414 |
| 22,369 |
| 14 |
| Sales(1) | 23,833 | | 17,066 | | 40 | | | 18,454 | | | 20,865 | | 20,381 | | 2 | |
| | | | | | | | | |
Net Income (Loss) | $ | (6,807 | ) | | $ | 3,130 |
| $ | (229,619 | ) | 101 |
| | $ | 9,094 |
| $ | (338,210 | ) | 103 |
| Net Income (Loss) | $ | 35,007 | | $ | (107,821) | | 132 | | | $ | (17,627) | | | $ | (20,042) | | $ | (730,096) | | 97 | |
| | | | | | |
|
| |
Operating Netback | | | | | | | | Operating Netback | |
Oil and Natural Gas Sales | $ | 96,128 |
| | $ | 103,768 |
| $ | 68,539 |
| 51 |
| | $ | 294,555 |
| $ | 197,655 |
| 49 |
| |
Oil Sales | | Oil Sales | $ | 135,319 | | $ | 53,142 | | 155 | | | $ | 96,623 | | | $ | 327,435 | | $ | 173,045 | | 89 | |
Operating Expenses | (27,208 | ) | | (27,321 | ) | (25,638 | ) | 7 |
| | (78,466 | ) | (62,453 | ) | 26 |
| Operating Expenses | (37,567) | | (20,721) | | 81 | | | (25,431) | | | (92,623) | | (84,673) | | 9 | |
| Transportation Expenses | (6,492 | ) | | (6,038 | ) | (5,773 | ) | 5 |
| | (19,472 | ) | (24,318 | ) | (20 | ) | Transportation Expenses | (3,021) | | (1,286) | | 135 | | | (2,921) | | | (8,448) | | (8,549) | | (1) | |
Operating Netback(2) | $ | 62,428 |
| | $ | 70,409 |
| $ | 37,128 |
| 90 |
| | $ | 196,617 |
| $ | 110,884 |
| 77 |
| Operating Netback(2) | $ | 94,731 | | $ | 31,135 | | 204 | | | $ | 68,271 | | | $ | 226,364 | | $ | 79,823 | | 184 | |
| | | | | | | | | |
General and Administrative ("G&A") Expenses, Including Stock-Based Compensation | $ | 9,513 |
| | $ | 8,651 |
| $ | 5,592 |
| 55 |
| | $ | 26,876 |
| $ | 20,614 |
| 30 |
| |
G&A Expenses Before Stock-Based Compensation | | G&A Expenses Before Stock-Based Compensation | $ | 5,444 | | $ | 4,506 | | 21 | | | $ | 7,133 | | | $ | 18,475 | | $ | 17,183 | | 8 | |
G&A Stock-Based Compensation Expense (Recovery) | | G&A Stock-Based Compensation Expense (Recovery) | 1,053 | | 56 | | 1,780 | | | 1,873 | | | 6,597 | | (707) | | 1,033 | |
G&A Expenses, Including Stock-Based Compensation | | G&A Expenses, Including Stock-Based Compensation | $ | 6,497 | | $ | 4,562 | | 42 | | | $ | 9,006 | | | $ | 25,072 | | $ | 16,476 | | 52 | |
| | | | | | | | | |
Adjusted EBITDA(2) | $ | 41,634 |
| | $ | 60,491 |
| $ | 24,634 |
| 146 |
| | $ | 163,663 |
| $ | 89,350 |
| 83 |
| Adjusted EBITDA(2) | $ | 81,804 | | $ | 21,884 | | 274 | | | $ | 36,299 | | | $ | 160,007 | | $ | 74,247 | | 116 | |
| | | | | | | | |
Funds Flow From Operations(2) | $ | 50,920 |
| | $ | 55,128 |
| $ | 23,527 |
| 134 |
| | $ | 151,074 |
| $ | 68,798 |
| 120 |
| Funds Flow From Operations(2) | $ | 69,103 | | $ | 8,056 | | 758 | | | $ | 23,272 | | | $ | 121,348 | | $ | 36,257 | | 235 | |
| | | | | | |
|
| |
Capital Expenditures | $ | 57,865 |
| | $ | 71,694 |
| $ | 25,080 |
| 186 |
| | $ | 175,719 |
| $ | 69,667 |
| 152 |
| Capital Expenditures | $ | 34,839 | | $ | 7,354 | | 374 | | | $ | 37,384 | | | $ | 109,650 | | $ | 56,378 | | 94 | |
|
| | | | | | | | |
| As at |
(Thousands of U.S. Dollars) | September 30, 2017 | December 31, 2016 | % Change |
Cash, Cash Equivalents and Current Restricted Cash and Cash Equivalents | $ | 19,045 |
| $ | 33,497 |
| (43 | ) |
| | | |
Revolving Credit Facility | $ | 120,000 |
| $ | 90,000 |
| 33 |
|
| | | |
Convertible Senior Notes | $ | 115,000 |
| $ | 115,000 |
| — |
|
(1) Sales volumes represent production NAR adjusted for inventory changes.
(2) Non-GAAP measures
Operating netback, EBITDA, adjusted EBITDA, and funds flow from operations and free cash flow 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(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. EachDisclosure of each non-GAAP financial measure is presented along withpreceded by 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 net of royalties andless 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.
Adjusted EBITDA, as presented, is defined as net income or loss adjusted for depletion, depreciation and accretion (“("DD&A”&A") expenses, asset impairment, interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for goodwill impairment, asset impairment, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, stock-based compensation expense or recovery, other-non cash gain or expense.loss, unrealized derivative instruments gain or loss and other financial instruments gain or loss. Management uses these financial measuresthis supplemental measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income, or loss, and believes that thesethis financial measures are also measure is
useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net income or loss to EBITDA and adjusted EBITDA is as follows:
| | | Three Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended June 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2017 | 2016 | | 2017 | 2016 | (Thousands of U.S. Dollars) | 2021 | 2020 | | 2021 | | 2021 | 2020 |
Net income (loss) | $ | (6,807 | ) | | $ | 3,130 |
| $ | (229,619 | ) | | $ | 9,094 |
| $ | (338,210 | ) | Net income (loss) | $ | 35,007 | | $ | (107,821) | | | $ | (17,627) | | | $ | (20,042) | | $ | (730,096) | |
Adjustments to reconcile net income (loss) to adjusted EBITDA | | | | | | |
Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA | | Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA | |
DD&A expenses | 31,644 |
| | 34,492 |
| 35,729 |
| | 92,729 |
| 104,525 |
| DD&A expenses | 38,055 | | 31,340 | | | 28,927 | | | 98,300 | | 131,118 | |
Asset impairment | 169 |
| | 787 |
| 319,974 |
| | 1,239 |
| 469,715 |
| |
Interest expense | 3,331 |
| | 3,989 |
| 5,122 |
| | 10,415 |
| 7,842 |
| Interest expense | 13,608 | | 14,029 | | | 13,935 | | | 41,355 | | 40,204 | |
Income tax expense (recovery) | 13,297 |
| | 18,093 |
| (106,572 | ) | | 50,186 |
| (154,522 | ) | Income tax expense (recovery) | 8,955 | | (20,565) | | | 9,189 | | | 26,795 | | (62,236) | |
EBITDA (non-GAAP) | | EBITDA (non-GAAP) | $ | 95,625 | | $ | (83,017) | | | $ | 34,424 | | | $ | 146,408 | | $ | (621,010) | |
Goodwill impairment | | Goodwill impairment | — | | — | | | — | | | — | | 102,581 | |
Asset impairment | | Asset impairment | — | | 104,731 | | | — | | | — | | 507,093 | |
Non-cash lease expense | | Non-cash lease expense | 408 | | 523 | | | 370 | | | 1,222 | | 1,494 | |
Lease payments | | Lease payments | (384) | | (429) | | | (393) | | | (1,239) | | (1,404) | |
Unrealized foreign exchange loss | | Unrealized foreign exchange loss | 3,465 | | 3,080 | | | 477 | | | 16,945 | | 22,335 | |
Stock-based compensation expense (recovery) | | Stock-based compensation expense (recovery) | 1,053 | | 56 | | | 1,873 | | | 6,597 | | (707) | |
Other non-cash loss | | Other non-cash loss | — | | 2,026 | | | — | | | — | | 2,026 | |
Unrealized derivative instruments (gain) loss | | Unrealized derivative instruments (gain) loss | (4,729) | | (6,546) | | | (3,066) | | | 2,499 | | 553 | |
Other financial instruments (gain) loss | | Other financial instruments (gain) loss | (13,634) | | 1,460 | | | 2,614 | | | (12,425) | | 61,286 | |
Adjusted EBITDA (non-GAAP) | $ | 41,634 |
| | $ | 60,491 |
| $ | 24,634 |
| | $ | 163,663 |
| $ | 89,350 |
| Adjusted EBITDA (non-GAAP) | $ | 81,804 | | $ | 21,884 | | | $ | 36,299 | | | $ | 160,007 | | $ | 74,247 | |
|
Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, goodwill and asset impairment, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, cash settlement of RSUs,non-cash lease expense, lease payments, unrealized foreign exchange gainsgain or loss, derivative instruments gain or loss, cash settlement on derivative instruments, other non-cash gain or loss and losses,other financial instruments gainsgain or losses, cash settlement of financial instruments, loss on sale of Brazil business unit and gain on acquisition.loss. 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. Free cash flow, as presented, is defined as funds flow less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements 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 and free cash flow is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Three Months Ended June 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | 2020 | | 2021 | | 2021 | 2020 |
Net income (loss) | $ | 35,007 | | $ | (107,821) | | | $ | (17,627) | | | $ | (20,042) | | $ | (730,096) | |
Adjustments to reconcile net income (loss) to funds flow from operations | | | | | | | |
DD&A expenses | 38,055 | | 31,340 | | | 28,927 | | | 98,300 | | 131,118 | |
Goodwill impairment | — | | — | | | — | | | — | | 102,581 | |
Asset impairment | — | | 104,731 | | | — | | | — | | 507,093 | |
Deferred tax expense (recovery) | 8,955 | | (21,202) | | | 9,203 | | | 26,809 | | (62,796) | |
Stock-based compensation expense (recovery) | 1,053 | | 56 | | | 1,873 | | | 6,597 | | (707) | |
Amortization of debt issuance costs | 907 | | 838 | | | 894 | | | 2,682 | | 2,774 | |
Non-cash lease expense | 408 | | 523 | | | 370 | | | 1,222 | | 1,494 | |
Lease payments | (384) | | (429) | | | (393) | | | (1,239) | | (1,404) | |
Unrealized foreign exchange loss | 3,465 | | 3,080 | | | 477 | | | 16,945 | | 22,335 | |
Derivative instruments loss (gain) | 2,603 | | (2,173) | | | 21,239 | | | 47,540 | | (9,417) | |
Cash settlements on derivative instruments | (7,332) | | (4,373) | | | (24,305) | | | (45,041) | | 9,970 | |
Other non-cash loss | — | | 2,026 | | | — | | | — | | 2,026 | |
Other financial instruments (gain) loss | (13,634) | | 1,460 | | | 2,614 | | | (12,425) | | 61,286 | |
Funds flow from operations (non-GAAP) | $ | 69,103 | | $ | 8,056 | | | $ | 23,272 | | | $ | 121,348 | | $ | 36,257 | |
Capital expenditures | $ | 34,839 | | $ | 7,354 | | | $ | 37,384 | | | $ | 109,650 | | $ | 56,378 | |
Free cash flow (non-GAAP) | $ | 34,264 | | $ | 702 | | | $ | (14,112) | | | $ | 11,698 | | $ | (20,121) | |
| | | | | | | |
| | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2017 | 2016 | | 2017 | 2016 |
Net income (loss) | $ | (6,807 | ) | | $ | 3,130 |
| $ | (229,619 | ) | | 9,094 |
| $ | (338,210 | ) |
Adjustments to reconcile net income (loss) to funds flow from operations | | | | | | | |
DD&A expenses | 31,644 |
| | 34,492 |
| 35,729 |
| | 92,729 |
| 104,525 |
|
Asset impairment | 169 |
| | 787 |
| 319,974 |
| | 1,239 |
| 469,715 |
|
Deferred tax expense (recovery) | 11,525 |
| | 13,760 |
| (110,451 | ) | | 36,664 |
| (166,202 | ) |
Stock-based compensation expense | 1,980 |
| | 1,752 |
| 858 |
| | 4,935 |
| 4,380 |
|
Amortization of debt issuance costs | 620 |
| | 643 |
| 2,184 |
| | 1,868 |
| 2,813 |
|
Cash settlement of RSUs | (183 | ) | | (33 | ) | (24 | ) | | (534 | ) | (1,210 | ) |
Unrealized foreign exchange loss (gain) | 3,895 |
| | (1,380 | ) | 2,387 |
| | (304 | ) | 2,437 |
|
Financial instruments (gain) loss | (1,447 | ) | | 1,675 |
| 2,051 |
| | (5,211 | ) | 1,824 |
|
Cash settlement of financial instruments | 448 |
| | 302 |
| 438 |
| | 1,518 |
| 438 |
|
Loss on sale of Brazil business unit | 9,076 |
| | — |
| — |
| | 9,076 |
| — |
|
Gain on acquisition | — |
| | — |
| — |
| | — |
| (11,712 | ) |
Funds flow from operations (non-GAAP) | $ | 50,920 |
| | $ | 55,128 |
| $ | 23,527 |
| | $ | 151,074 |
| $ | 68,798 |
|
Additional Operational Results
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Three Months Ended June 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | 2020 | % Change | | 2021 | | 2021 | 2020 | % Change |
Oil sales | $ | 135,319 | | $ | 53,142 | | 155 | | | $ | 96,623 | | | $ | 327,435 | | $ | 173,045 | | 89 | |
Operating expenses | 37,567 | | 20,721 | | 81 | | | 25,431 | | | 92,623 | | 84,673 | | 9 | |
| | | | | | | | | |
Transportation expenses | 3,021 | | 1,286 | | 135 | | | 2,921 | | | 8,448 | | 8,549 | | (1) | |
Operating netback(1) | 94,731 | | 31,135 | | 204 | | | 68,271 | | | 226,364 | | 79,823 | | 184 | |
| | | | | | | | | |
COVID-19 related costs | 990 | | 1,108 | | (11) | | | 897 | | | 3,026 | | 1,529 | | 98 | |
DD&A expenses | 38,055 | | 31,340 | | 21 | | | 28,927 | | | 98,300 | | 131,118 | | (25) | |
Goodwill impairment | — | | — | | — | | | — | | | — | | 102,581 | | (100) | |
Asset impairment | — | | 104,731 | | (100) | | | — | | | — | | 507,093 | | (100) | |
G&A expenses before stock-based compensation | 5,444 | | 4,506 | | 21 | | | 7,133 | | | 18,475 | | 17,183 | | 8 | |
G&A stock-based compensation expense (recovery) | 1,053 | | 56 | | 1,780 | | | 1,873 | | | 6,597 | | (707) | | 1,033 | |
Severance expenses | — | | 122 | | (100) | | | — | | | 919 | | 1,469 | | (37) | |
Foreign exchange loss | 2,650 | | 4,275 | | (38) | | | 91 | | | 15,824 | | 20,094 | | (21) | |
Derivative instruments loss (gain) | 2,603 | | (2,173) | | 220 | | | 21,239 | | | 47,540 | | (9,417) | | 605 | |
Other financial instruments (gain) loss | (13,634) | | 1,460 | | (1,034) | | | 2,614 | | | (12,425) | | 61,286 | | (120) | |
Other loss | — | | 67 | | (100) | | | — | | | — | | 67 | | (100) | |
Interest expense | 13,608 | | 14,029 | | (3) | | | 13,935 | | | 41,355 | | 40,204 | | 3 | |
| 50,769 | | 159,521 | | (68) | | | 76,709 | | | 219,611 | | 872,500 | | (75) | |
| | | | | | | | | |
Interest income | — | | — | | — | | | — | | | — | | 345 | | (100) | |
| | | | | | | | | |
Income (loss) before income taxes | 43,962 | | (128,386) | | 134 | | | (8,438) | | | 6,753 | | (792,332) | | 101 | |
| | | | | | | | | |
Current income tax expense (recovery) | — | | 637 | | (100) | | | (14) | | | (14) | | 560 | | (103) | |
Deferred income tax expense (recovery) | 8,955 | | (21,202) | | 142 | | | 9,203 | | | 26,809 | | (62,796) | | 143 | |
| 8,955 | | (20,565) | | 144 | | | 9,189 | | | 26,795 | | (62,236) | | 143 | |
Net income (loss) | $ | 35,007 | | $ | (107,821) | | 132 | | | $ | (17,627) | | | $ | (20,042) | | $ | (730,096) | | 97 | |
| | | | | | | | | |
Sales Volumes (NAR) | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total sales volumes, BOPD | 23,833 | | 17,066 | | 40 | | | 18,454 | | | 20,865 | | 20,381 | | 2 | |
| | | | | | | | | |
Brent Price per bbl | $ | 73.23 | | $ | 43.34 | | 69 | | | $ | 69.08 | | | $ | 67.97 | | $ | 42.53 | | 60 | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2017 | 2016 | % Change | | 2017 | 2016 | % Change |
(Thousands of U.S. Dollars) | | | | | | | | | |
Oil and natural gas sales | $ | 96,128 |
| | $ | 103,768 |
| $ | 68,539 |
| 51 |
| | $ | 294,555 |
| $ | 197,655 |
| 49 |
|
Operating expenses | 27,208 |
| | 27,321 |
| 25,638 |
| 7 |
| | 78,466 |
| 62,453 |
| 26 |
|
Transportation expenses | 6,492 |
| | 6,038 |
| 5,773 |
| 5 |
| | 19,472 |
| 24,318 |
| (20 | ) |
Operating netback(1) | 62,428 |
| | 70,409 |
| 37,128 |
| 90 |
| | 196,617 |
| 110,884 |
| 77 |
|
| | | | | | | | | |
DD&A expenses | 31,644 |
| | 34,492 |
| 35,729 |
| (3 | ) | | 92,729 |
| 104,525 |
| (11 | ) |
Asset impairment | 169 |
| | 787 |
| 319,974 |
| (100 | ) | | 1,239 |
| 469,715 |
| (100 | ) |
G&A expenses before stock-based compensation | 7,610 |
| | 6,965 |
| 4,778 |
| 46 |
| | 22,138 |
| 16,414 |
| 35 |
|
G&A stock-based compensation expense | 1,903 |
| | 1,686 |
| 814 |
| 107 |
| | 4,738 |
| 4,200 |
| 13 |
|
Severance expenses | — |
| | 1,164 |
| — |
| — |
| | 1,164 |
| 1,299 |
| (10 | ) |
Transaction expenses | — |
| | — |
| 6,088 |
| (100 | ) | | — |
| 7,325 |
| (100 | ) |
Equity tax | — |
| | — |
| — |
| — |
| | 1,224 |
| 3,053 |
| (60 | ) |
Foreign exchange loss (gain) | 3,897 |
| | (1,271 | ) | (507 | ) | (151 | ) | | 779 |
| 1,059 |
| (26 | ) |
Financial instruments (gain) loss | (1,447 | ) | | 1,675 |
| 2,051 |
| (18 | ) | | (5,211 | ) | 1,824 |
| (386 | ) |
Interest expense | 3,331 |
| | 3,989 |
| 5,122 |
| (22 | ) | | 10,415 |
| 7,842 |
| 33 |
|
| 47,107 |
| | 49,487 |
| 374,049 |
| (87 | ) | | 129,215 |
| 617,256 |
| (79 | ) |
| | | | | | | | | |
Loss on sale of Brazil business unit | (9,076 | ) | | — |
| — |
| — |
| | (9,076 | ) | — |
| — |
|
Gain on acquisition | — |
| | — |
| — |
| — |
| | — |
| 11,712 |
| (100 | ) |
Interest income | 245 |
| | 301 |
| 730 |
| (59 | ) | | 954 |
| 1,928 |
| (51 | ) |
| | | | | | | | |
|
Income (loss) before income taxes | 6,490 |
| | 21,223 |
| (336,191 | ) | 106 |
| | 59,280 |
| (492,732 | ) | 112 |
|
| | | | | | | | | |
Current income tax expense | 1,772 |
| | 4,333 |
| 3,879 |
| 12 |
| | 13,522 |
| 11,680 |
| 16 |
|
Deferred income tax expense (recovery) | 11,525 |
| | 13,760 |
| (110,451 | ) | 112 |
| | 36,664 |
| (166,202 | ) | 122 |
|
| 13,297 |
| | 18,093 |
| (106,572 | ) | 117 |
| | 50,186 |
| (154,522 | ) | 132 |
|
Net income (loss) | $ | (6,807 | ) | | $ | 3,130 |
| $ | (229,619 | ) | 101 |
|
| $ | 9,094 |
| $ | (338,210 | ) | 103 |
|
| | | | | | | | |
|
Sales Volumes (NAR) | | | | | | | | |
|
Total sales volumes, BOEPD | 26,283 |
| | 27,447 |
| 21,485 |
| 28 |
| | 26,189 |
| 23,105 |
| 13 |
|
| | | | | | | | |
|
Average Prices | | | | | | | | |
|
Oil and NGL's per bbl | $ | 40.44 |
| | $ | 41.44 |
| $ | 34.79 |
| 19 |
| | $ | 41.58 |
| $ | 31.34 |
| 33 |
|
Natural gas per Mcf | $ | 2.52 |
| | $ | 1.89 |
| $ | 3.40 |
| (44 | ) | | $ | 1.90 |
| $ | 3.07 |
| (38 | ) |
| | | | | | | | |
|
|
Brent Price per bbl | $ | 50.92 |
| | $ | 52.18 |
| $ | 46.98 |
| 11 |
| | $ | 52.59 |
| $ | 42.07 |
| 25 |
|
| | | | | | | | | |
| | Consolidated Results of Operations per BOE Sales Volumes NAR | | | | | | |
|
| |
Oil and natural gas sales | $ | 40.19 |
| | $ | 41.09 |
| $ | 34.68 |
| 18 |
| | $ | 41.20 |
| $ | 31.22 |
| 32 |
| |
Consolidated Results of Operations per bbl Sales Volumes NAR | | Consolidated Results of Operations per bbl Sales Volumes NAR | |
Oil sales | | Oil sales | $ | 61.72 | | $ | 33.85 | | 82 | | | $ | 57.54 | | | $ | 57.48 | | $ | 30.99 | | 85 | |
Operating expenses | 11.38 |
| | 10.82 |
| 12.97 |
| (17 | ) | | 10.97 |
| 9.86 |
| 11 |
| Operating expenses | 17.13 | | 13.20 | | 30 | | | 15.14 | | | 16.26 | | 15.16 | | 7 | |
Transportation expenses | 2.71 |
| | 2.39 |
| 2.92 |
| (18 | ) | | 2.72 |
| 3.84 |
| (29 | ) | Transportation expenses | 1.38 | | 0.82 | | 68 | | | 1.74 | | | 1.48 | | 1.53 | | (3) | |
Operating netback(1) | 26.10 |
| | 27.88 |
| 18.79 |
| 48 |
| | 27.51 |
| 17.52 |
| 57 |
| Operating netback(1) | 43.21 | | 19.83 | | 118 | | | 40.66 | | | 39.74 | | 14.30 | | 178 | |
| | | | | | | | | |
COVID-19 related costs | | COVID-19 related costs | 0.45 | | 0.70 | | (36) | | | 0.53 | | | 0.53 | | 0.27 | | 96 | |
DD&A expenses | 13.23 |
| | 13.66 |
| 18.08 |
| (24 | ) | | 12.97 |
| 16.51 |
| (21 | ) | DD&A expenses | 17.36 | | 19.96 | | (13) | | | 17.23 | | | 17.26 | | 23.48 | | (26) | |
Goodwill impairment | | Goodwill impairment | — | | — | | — | | | — | | | — | | 18.37 | | (100) | |
Asset impairment | 0.07 |
| | 0.31 |
| 161.88 |
| (100 | ) | | 0.17 |
| 74.20 |
| (100 | ) | Asset impairment | — | | 66.71 | | (100) | | | — | | | — | | 90.80 | | (100) | |
G&A expenses before stock-based compensation | 3.18 |
| | 2.76 |
| 2.42 |
| 14 |
| | 3.10 |
| 2.60 |
| 19 |
| G&A expenses before stock-based compensation | 2.48 | | 2.87 | | (14) | | | 4.25 | | | 3.24 | | 3.08 | | 5 | |
G&A stock-based compensation expense | 0.80 |
| | 0.67 |
| 0.41 |
| 63 |
| | 0.66 |
| 0.66 |
| — |
| |
G&A stock-based compensation expense (recovery) | | G&A stock-based compensation expense (recovery) | 0.48 | | 0.04 | | 1,100 | | | 1.12 | | | 1.16 | | (0.13) | | 992 | |
Severance expenses | — |
| | 0.46 |
| — |
| — |
| | 0.16 |
| 0.21 |
| (24 | ) | Severance expenses | — | | 0.08 | | (100) | | | — | | | 0.16 | | 0.26 | | (38) | |
Transaction expenses | — |
| | — |
| 3.08 |
| (100 | ) | | — |
| 1.16 |
| (100 | ) | |
Equity tax | — |
| | — |
| — |
| — |
| | 0.17 |
| 0.48 |
| (65 | ) | |
Foreign exchange loss (gain) | 1.63 |
| | (0.50 | ) | (0.26 | ) | (92 | ) | | 0.11 |
| 0.17 |
| (35 | ) | |
Financial instruments (gain) loss | (0.60 | ) | | 0.66 |
| 1.04 |
| (37 | ) | | (0.73 | ) | 0.29 |
| (352 | ) | |
Foreign exchange loss | | Foreign exchange loss | 1.21 | | 2.72 | | (56) | | | 0.05 | | | 2.78 | | 3.60 | | (23) | |
Derivative instruments loss (gain) | | Derivative instruments loss (gain) | 1.19 | | (1.38) | | 186 | | | 12.65 | | | 8.35 | | (1.69) | | 594 | |
Other financial instruments (gain) loss | | Other financial instruments (gain) loss | (6.22) | | 0.93 | | (769) | | | 1.56 | | | (2.18) | | 10.97 | | (120) | |
Other loss | | Other loss | — | | 0.04 | | (100) | | | — | | | — | | 0.01 | | (100) | |
Interest expense | 1.39 |
| | 1.58 |
| 2.59 |
| (39 | ) | | 1.46 |
| 1.24 |
| 18 |
| Interest expense | 6.21 | | 8.94 | | (31) | | | 8.30 | | | 7.26 | | 7.20 | | 1 | |
| 19.70 | | 19.60 | 189.24 | (90 | ) | | 18.07 | 97.52 | (81 | ) | | 23.16 | | 101.61 | | (77) | | | 45.69 | | | 38.56 | | 156.22 | | (75) | |
| | | | | | | | |
Loss on sale of Brazil business unit | (3.79 | ) | | — |
| — |
| — |
| | (1.27 | ) | — |
| — |
| |
Gain on acquisition | — |
| | — |
| — |
| — |
| | — |
| 1.85 |
| (100 | ) | |
| Interest income | 0.10 |
| | 0.12 |
| 0.37 |
| (68 | ) | | 0.13 |
| 0.30 |
| (57 | ) | Interest income | — | | — | | — | | | — | | | — | | 0.06 | | (100) | |
| | | | | | |
|
| | |
Income (loss) before income taxes | 2.71 |
| | 8.40 |
| (170.08 | ) | 105 |
| | 8.30 |
| (77.85 | ) | 111 |
| Income (loss) before income taxes | 20.05 | | (81.78) | | 125 | | | (5.03) | | | 1.18 | | (141.86) | | 101 | |
Current income tax expense | 0.74 |
| | 1.72 |
| 1.96 |
| (12 | ) | | 1.89 |
| 1.84 |
| 3 |
| |
| Current income tax expense (recovery) | | Current income tax expense (recovery) | — | | 0.41 | | (100) | | | (0.01) | | | — | | 0.10 | | (100) | |
Deferred income tax expense (recovery) | 4.82 |
| | 5.45 |
| (55.88 | ) | 110 |
| | 5.13 |
| (26.25 | ) | 120 |
| Deferred income tax expense (recovery) | 4.08 | | (13.50) | | 130 | | | 5.48 | | | 4.71 | | (11.24) | | 142 | |
| 5.56 |
| | 7.17 |
| (53.92 | ) | 113 |
| | 7.02 |
| (24.41 | ) | 129 |
| | 4.08 | | (13.09) | | 131 | | | 5.47 | | | 4.71 | | (11.14) | | 142 | |
Net income (loss) | $ | (2.85 | ) | | $ | 1.23 |
| $ | (116.16 | ) | 101 |
| | $ | 1.28 |
| $ | (53.44 | ) | 102 |
| Net income (loss) | $ | 15.97 | | $ | (68.69) | | 123 | | | $ | (10.50) | | | $ | (3.53) | | $ | (130.72) | | 97 | |
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and OperatingOperational Highlights—non-GAAP measures" for a definition and reconciliation of this measure.
As previously announced, we continue to evaluate strategic disposition alternatives for our assets in Peru, which may not be core to our ongoing plans. Any such disposition may involve a contribution of such assets to a separate entity in which we would retain a non-controlling equity interest. The new company may engage in external capital raising activities to fund the ongoing development of the Peruvian assets. We have not entered into any definitive agreement and cannot provide assurances that any disposition will be completed.
Oil and Gas Production and Sales Volumes, BOEPDBOPD
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | 2020 |
Average Daily Volumes (BOPD) | | | | | |
WI Production Before Royalties | 28,957 | | 18,944 | | | 25,501 | | 22,864 | |
Royalties | (5,585) | | (1,893) | | | (4,531) | | (2,600) | |
Production NAR | 23,372 | | 17,051 | | | 20,970 | | 20,264 | |
Decrease (Increase) in Inventory | 461 | | 15 | | | (105) | | 117 | |
Sales | 23,833 | | 17,066 | | | 20,865 | | 20,381 | |
| | | | | |
Royalties, % of WI Production Before Royalties | 19 | % | 10 | % | | 18 | % | 11 | % |
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 |
Average Daily Volumes (BOEPD) | Colombia | Brazil | Total | | Colombia | Brazil | Total |
Working Interest Production Before Royalties | 32,570 |
| — |
| 32,570 |
| | 24,874 |
| 961 |
| 25,835 |
|
Royalties | (5,055 | ) | — |
| (5,055 | ) | | (3,717 | ) | (138 | ) | (3,855 | ) |
Production NAR | 27,515 |
| — |
| 27,515 |
|
| 21,157 |
| 823 |
| 21,980 |
|
(Increase) Decrease in Inventory | (68 | ) | — |
| (68 | ) | | (497 | ) | 2 |
| (495 | ) |
Sales | 27,447 |
| — |
| 27,447 |
|
| 20,660 |
| 825 |
| 21,485 |
|
| | | | | | | |
Royalties, % of Working Interest Production Before Royalties | 16 | % | — | % | 16 | % | | 15 | % | 14 | % | 15 | % |
| | | | | | | |
| Nine Months Ended September 30, 2017 | | Nine Months Ended September 30, 2016 |
Average Daily Volumes (BOEPD) | Colombia | Brazil | Total | | Colombia | Brazil | Total |
Working Interest Production Before Royalties | 30,398 |
| 907 |
| 31,305 |
| | 24,859 |
| 871 |
| 25,730 |
|
Royalties | (4,914 | ) | (138 | ) | (5,052 | ) | | (3,439 | ) | (137 | ) | (3,576 | ) |
Production NAR | 25,484 |
| 769 |
| 26,253 |
| | 21,420 |
| 734 |
| 22,154 |
|
(Increase) Decrease in Inventory | (70 | ) | 6 |
| (64 | ) | | 949 |
| 2 |
| 951 |
|
Sales | 25,414 |
| 775 |
| 26,189 |
| | 22,369 |
| 736 |
| 23,105 |
|
| | | | | | | |
Royalties, % of Working Interest Production Before Royalties | 16 | % | 15 | % | 16 | % | | 14 | % | 16 | % | 14 | % |
Oil and gas production NARfor the three and nine months ended September 30, 2017,2021, increased by 25% to 27,515 BOEPD37% and 19% to 26,253 BOEPD,3%, respectively, compared with 21,980 BOEPD and 22,154 BOEPD respectively, into the comparablecorresponding periods in 2016. We increased oil and gas production NAR despite the sale of our Brazil business unit on June 30, 2017. In the three and nine months ended September 30, 2017, production increased primarily2020 due to the PetroLatina acquisition and a successful drilling and workover campaign in all major fields, despite production disruptions during the Acordionero Fieldsecond quarter of 2021 caused by national blockades in Colombia. The acquisitionCompared to the prior quarter, oil production NAR increased 23% as the national blockades were resolved by the end of PetroLatina Energy Limited closed on August 23, 2016, at which time the Acordionero field was producing approximately 4,730 bopd before royalties. After a successful drilling campaign, production from the Acordionero Field averaged 10,743 bopd and 8,451 bopd, respectively, before royalties during the three and nine months ended September 30, 2017second quarter of 2021.
Royalties as a percentage of production for the three and nine months ended September 30, 2017,2021, increased compared with the comparable period incorresponding periods of 2020 and the prior yearquarter commensurate with the increase in benchmark oil prices.prices and the price sensitive royalty regime in Colombia.
Despite the sale of our Brazil assets effective June 30, 2017, oil and gas production NAR for the three months ended September 30, 2017, increased 4% compared with the prior quarter as a result of a successful drilling and workover campaign in
The Midas block includes the Acordionero, Field in Colombia,Mochuelo, and Ayombero oil fields, and the successful Vonu-1 exploration wellChaza block includes the Costayaco and a workover campaign in Cumplidor. Colombian NAR production increased 9% compared with the prior quarter.Moqueta oil fields.
Oil and gas sales volumes for the three months ended September 30, 2017, increased by 28% to 27,447 BOEPD compared with 21,485 BOEPD in the corresponding period in 2016. Higher working interest production (6,735 BOEPD) and lower inventory increases (427 BOEPD) more than offset higher royalty volumes (1,200 BOEPD).
For the nine months ended September 30, 2017, oil and gas sales volumesincreased by 13% to 26,189 BOEPD compared with 23,105 BOEPD in the corresponding period in 2016. Higher working interest production (5,575 BOEPD) more than offset the combination of higher royalty volumes (1,476 BOEPD) and inventory changes (1,015 BOEPD).
Oil and gas sales volumes for the three months ended September 30, 2017, increased by 4% to 27,447 BOEPD compared with 26,283 BOEPD in the prior quarter. Sales volumes increased due to higher working interest production (1,133 BOEPD) and lower inventory changes (72 BOEPD) more than offset higher royalty volumes (41 BOEPD).
Operating NetbacksNetback
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Three Months Ended June 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | 2020 | | 2021 | | 2021 | 2020 |
| | | | | | | |
Oil Sales | $ | 135,319 | | $ | 53,142 | | | $ | 96,623 | | | $ | 327,435 | | $ | 173,045 | |
Transportation Expenses | (3,021) | | (1,286) | | | (2,921) | | | (8,448) | | (8,549) | |
| 132,298 | | 51,856 | | | 93,702 | | | 318,987 | | 164,496 | |
Operating Expenses | (37,567) | | (20,721) | | | (25,431) | | | (92,623) | | (84,673) | |
Operating Netback(1) | $ | 94,731 | | $ | 31,135 | | | $ | 68,271 | | | $ | 226,364 | | $ | 79,823 | |
| | | | | | | |
(U.S. Dollars Per bbl Sales Volumes NAR) | | | | | | | |
Brent | $ | 73.23 | | $ | 43.34 | | | $ | 69.08 | | | $ | 67.97 | | $ | 42.53 | |
Quality and Transportation Discounts | (11.51) | | (9.49) | | | (11.54) | | | (10.49) | | (11.54) | |
Average Realized Price | 61.72 | | 33.85 | | | 57.54 | | | 57.48 | | 30.99 | |
Transportation Expenses | (1.38) | | (0.82) | | | (1.74) | | | (1.48) | | (1.53) | |
Average Realized Price Net of Transportation Expenses | 60.34 | | 33.03 | | | 55.80 | | | 56.00 | | 29.46 | |
Operating Expenses | (17.13) | | (13.20) | | | (15.14) | | | (16.26) | | (15.16) | |
Operating Netback(1) | $ | 43.21 | | $ | 19.83 | | | $ | 40.66 | | | $ | 39.74 | | $ | 14.30 | |
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 |
(Thousands of U.S. Dollars) | Colombia | Brazil | Total | | Colombia | Brazil | Total |
Oil and Natural Gas Sales | $ | 103,768 |
| $ | — |
| $ | 103,768 |
| | $ | 65,944 |
| $ | 2,595 |
| $ | 68,539 |
|
Transportation Expenses | (6,038 | ) | — |
| (6,038 | ) | | (5,644 | ) | (129 | ) | (5,773 | ) |
| 97,730 |
| — |
| 97,730 |
| | 60,300 |
| 2,466 |
| 62,766 |
|
Operating Expenses | (27,321 | ) | — |
| (27,321 | ) | | (24,899 | ) | (739 | ) | (25,638 | ) |
Operating Netback(1) | $ | 70,409 |
| $ | — |
| $ | 70,409 |
| | $ | 35,401 |
| $ | 1,727 |
| $ | 37,128 |
|
| | | | | | | |
U.S. Dollars Per BOE Sales Volumes NAR | | | | | | | |
Brent | $ | 52.18 |
| $ | — |
| $ | 52.18 |
| | $ | 46.98 |
| $ | 46.98 |
| $ | 46.98 |
|
Quality and Transportation Discounts | (11.09 | ) | — |
| (11.09 | ) | | (12.29 | ) | (12.77 | ) | (12.30 | ) |
Average Realized Price | 41.09 |
| — |
| 41.09 |
| | 34.69 |
| 34.21 |
| 34.68 |
|
Transportation Expenses | (2.39 | ) | — |
| (2.39 | ) | | (2.97 | ) | (1.70 | ) | (2.92 | ) |
Average Realized Price Net of Transportation Expenses | 38.70 |
| — |
| 38.70 |
| | 31.72 |
| 32.51 |
| 31.76 |
|
Operating Expenses | (10.82 | ) | — |
| (10.82 | ) | | (13.10 | ) | (9.74 | ) | (12.97 | ) |
Operating Netback(1) | $ | 27.88 |
| $ | — |
| $ | 27.88 |
| | $ | 18.62 |
| $ | 22.77 |
| $ | 18.79 |
|
| | | | | | | |
| Nine Months Ended September 30, 2017 | | Nine Months Ended September 30, 2016 |
(Thousands of U.S. Dollars) | Colombia | Brazil | Total | | Colombia | Brazil | Total |
Oil and Natural Gas Sales | $ | 286,137 |
| $ | 8,418 |
| $ | 294,555 |
| | $ | 191,515 |
| $ | 6,140 |
| $ | 197,655 |
|
Transportation Expenses | (19,122 | ) | (350 | ) | (19,472 | ) | | (24,005 | ) | (313 | ) | (24,318 | ) |
| 267,015 |
| 8,068 |
| 275,083 |
| | 167,510 |
| 5,827 |
| 173,337 |
|
Operating Expenses | (76,669 | ) | (1,797 | ) | (78,466 | ) | | (61,057 | ) | (1,396 | ) | (62,453 | ) |
Operating Netback(1) | $ | 190,346 |
| $ | 6,271 |
| $ | 196,617 |
| | $ | 106,453 |
| $ | 4,431 |
| $ | 110,884 |
|
| | | | | | | |
U.S. Dollars Per BOE Sales Volumes NAR | | | | | | | |
Brent | $ | 52.59 |
| $ | 52.59 |
| $ | 52.59 |
| | $ | 42.07 |
| $ | 42.07 |
| $ | 42.07 |
|
Quality and Transportation Discounts | (11.35 | ) | (12.83 | ) | (11.39 | ) | | (10.82 | ) | (11.61 | ) | (10.85 | ) |
Average Realized Price | 41.24 |
| 39.76 |
| 41.20 |
| | 31.25 |
| 30.46 |
| 31.22 |
|
Transportation Expenses | (2.76 | ) | (1.65 | ) | (2.72 | ) | | (3.92 | ) | (1.55 | ) | (3.84 | ) |
Average Realized Price Net of Transportation Expenses | 38.48 |
| 38.11 |
| 38.48 |
| | 27.33 |
| 28.91 |
| 27.38 |
|
Operating Expenses | (11.05 | ) | (8.49 | ) | (10.97 | ) | | (9.96 | ) | (6.92 | ) | (9.86 | ) |
Operating Netback(1) | $ | 27.43 |
| $ | 29.62 |
| $ | 27.51 |
| | $ | 17.37 |
| $ | 21.99 |
| $ | 17.52 |
|
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operational Highlights—non-GAAP measures disclosure above regardingmeasures" for a definition of this measure.
Oil and gas sales for the three months ended September 30, 2021, increased by 155% to $135.3 million due to a 69% increase in Brent price and 40% higher sales volumes partially offset by a 21% increase in the quality and transportation discounts as a result of the widening of the Castilla and Vasconia differentials compared to the corresponding period of 2020. Both the Castilla and Vasconia differentials have widened from $4.65 and $3.01 in the third quarter of 2020 to $6.51 and $4.02 in the third quarter of 2021, respectively. For the nine months ended September 30, 2017,2021, oil sales increased by 51%89% to $103.8$327.4 million and by 49%compared to $294.6 million, respectively, from $68.5 million and $197.7 million, respectively, in the comparable periods in 2016corresponding period of 2020 due to increaseda 60% increase in Brent price, higher sales volumes, and realizedlower quality and transportation discounts. Compared with the prior quarter, oil prices.sales increased 40% primarily as a result of a 6% increase in Brent price and a 29% increase in sales volumes.
The following table shows the effect of changes in realized pricesprice and sales volumes on our oil and gas sales for the three and nine months ended September 30, 2017:2021, compared to the prior quarter and the corresponding periods of 2020:
| | | | | | | | | | | | | | | | | |
(Thousands of U.S. Dollars) | Third Quarter 2021 Compared with Second Quarter 2021 | | Third Quarter 2021 Compared with Third Quarter 2020 | | Nine Months Ended September 30, 2021 Compared with Nine Months Ended September 30, 2020 |
Oil sales for the comparative period | $ | 96,623 | | | $ | 53,142 | | | $ | 173,045 | |
Realized sales price increase effect | 9,162 | | | 61,106 | | | 150,930 | |
Sales volumes increase effect | 29,534 | | | 21,071 | | | 3,460 | |
Oil sales for the three and nine months ended September 30, 2021 | $ | 135,319 | | | $ | 135,319 | | | $ | 327,435 | |
|
| | | | | | | | | |
| Third Quarter 2017 Compared with Second Quarter 2017 | Third Quarter 2017 Compared with Third Quarter 2016 | Nine Months Ended, September 30, 2017 Compared with Nine Months Ended September 30, 2016 |
Oil and natural gas sales for the comparative period | $ | 96,128 |
| $ | 68,539 |
| $ | 197,655 |
|
Realized sales price increase effect | 2,285 |
| 16,206 |
| 71,333 |
|
Sales volume increase effect | 5,355 |
| 19,023 |
| 25,567 |
|
Oil and natural gas sales for period ended September 30, 2017 | $ | 103,768 |
| $ | 103,768 |
| $ | 294,555 |
|
AverageThe average realized pricesprice for the three and nine months ended September 30, 2017,2021, increased by 18%82% and 32%85%, respectively, compared to the corresponding periods of 2020. The increases were commensurate with the increaserise in benchmark oil prices and for the nine month period lower transportationVasconia and quality discounts. Average BrentCastilla differentials, but for the three month period were partially offset by higher Vasconia and Castilla differentials. Compared to the prior quarter, the average realized price increased 7% due to higher benchmark oil prices offset by higher differentials.
Operating expenses for the three and nine months ended September 30, 2017,2021, increased by 11%$3.93 and 25% respectively.
Oil$1.10 per bbl to $37.6 million and gas sales for$92.6 million or $17.13 and $16.26 per bbl primarily due to increased operating activities and higher power generation costs in Acordionero when compared to the three months ended September 30, 2017, increased by 8%corresponding periods of 2020. Lower operating activities during most of 2020 were attributed to $103.8 million from $96.1 million compared withthe shut-in of higher-cost wells in response to the COVID-19 pandemic. Compared to the prior quarter, operating expenses increased $1.99 per bbl from $25.4 million or $15.14 per bbl due to higher sales volumescosts associated with power generation and chemical costs in Acordionero and increased realized oil prices. Average realized prices increased by 2% to $41.09 per BOE for the three months ended September 30, 2017, compared with $40.19 per BOE in the prior quarter. Average Brent oil prices for the three months ended September 30, 2017, increased by 2% to $52.18 per bbl, compared with $50.92 per bbl in the prior quarter.workover activity.
We have options to sell our oil thoughthrough multiple pipelines and trucking routes. Each transportation routeoption has varying effects on realized pricessales price and transportation expenses. The following table shows the percentage of oil volumes we sold in Colombia using each transportation methodoption for the three and nine months ended September 30, 2017 and 20162021, 2020, and the prior quarter:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Three Months Ended June 30, | | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | | 2021 | 2020 |
Volume transported through pipeline | 9 | % | — | % | | 9 | % | | 6 | % | 5 | % |
Volume sold at wellhead | 42 | % | 48 | % | | 24 | % | | 55 | % | 45 | % |
Volume transported via truck to sales point | 49 | % | 52 | % | | 67 | % | | 39 | % | 50 | % |
| 100 | % | 100 | % | | 100 | % | | 100 | % | 100 | % |
|
| | | | | | | | | | |
| Three Months Ended June 30, | Three Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | 2017 | 2016 | 2017 | 2016 |
Volume transported through pipeline | 20 | % | 10 | % | 36 | % | 18 | % | 50 | % |
Volume sold at wellhead, trucking | 52 | % | 57 | % | 56 | % | 54 | % | 40 | % |
Volume sold not at wellhead, trucking | 28 | % | 33 | % | 8 | % | 28 | % | 10 | % |
| 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
Volumes not sold at the wellheadtransported through pipeline or via truck receive a higher realized price but incur higher transportation expenses. VolumesConversely, volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense.expenses.
Transportation expenses for the three months ended September 30, 2017,2021, increased by 5%135% to $6.0$3.0 million and on a per bbl basis increased by 68% to $1.38 compared withto the corresponding period in 2016. On a per BOE basis, transportation expenses decreased by 18% to $2.39 per BOE from $2.92 per BOE in the corresponding period in 2016. The decrease in transportation expenses per BOE wasof 2020 due to maintenance on the useImpala terminal resulting in utilization of alternative transportation routes which had lowerhigher costs per BOE than the routes used in 2016.
Transportation expenses forbbl. For the nine months ended September 30, 2017, decreased by 20% to $19.5 million compared with the corresponding period in 2016. On a per BOE basis,2021, transportation expenses decreased by 29%1% to $2.72$8.4 million and on a per BOE from $3.84 per BOE inbbl basis decreased by 3% to $1.48 when compared to the corresponding period in 2016. The decrease in transportation expenses per BOE was due toof 2020, as a result of higher percentage of volumes sold at the wellhead as notedduring the current period which resulted in the table above, and the use oflower transportation routes which had lower costs per BOE than the routes used in 2016.costs.
Transportation expenses for
For the three months ended September 30, 2017, decreased 7%2021, transportation expenses increased by 3% compared to $6.0 million compared with $6.5$2.9 million in the prior quarter.quarter due to increased sales volumes. On a per BOEbbl basis, transportation expenses decreased by 12% to $2.3921% from $2.71$1.74 in the prior quarter. The decrease was primarilyprevious quarter due to the use ofCompany utilizing more favorable transportation routes which had loweras all blockades were lifted.
COVID-19 Costs
The COVID-19 pandemic has resulted in extra ongoing operating and transportation costs per BOE.
The following table showsrelated to COVID-19 health and safety preventative measures, including incremental sanitation requirements and enhanced procedures for trucking barrels and crew changes in the variance in our average realized prices netfield. For the three and nine months ended September 30, 2021, COVID-19 costs were $1.0 million and $3.0 million, respectively, comprised of $0.9 million and $2.7 million related to operating activities and $0.1 million and $0.3 million related to transportation expenses in Colombiaactivities. There were $1.1 million and $1.5 million COVID-19 costs for the three and nine months ended September 30, 2017 compared with the comparative period in 2016 and the prior quarter:
|
| | | | | | | | | |
U.S. Dollars Per BOE Sales Volumes NAR | Third Quarter 2017 Compared with Second Quarter 2017 | Third Quarter 2017 Compared with Third Quarter 2016 | Nine Months Ended, September 30, 2017 Compared with Nine Months Ended September 30, 2016 |
Average realized price net of transportation expenses for the comparative period | $ | 37.42 |
| $ | 31.72 |
| $ | 27.33 |
|
Increase in benchmark prices | 1.26 |
| $ | 5.20 |
| 10.52 |
|
(Increase) decrease in quality and transportation discounts | (0.35 | ) | 1.20 |
| (0.53 | ) |
Lower transportation expenses | 0.37 |
| 0.58 |
| 1.16 |
|
Average realized price net of transportation expenses for period ended September 30, 2017 | $ | 38.70 |
| $ | 38.70 |
| $ | 38.48 |
|
Operating expenses for the three months ended September 30, 2017, increased by 7% to $27.3 million compared with the corresponding period in 2016. The increase was primarily due to higher sales volumes. On a per BOE basis, operating expenses decreased by 17% to $10.82 per BOE from $12.97 per BOE, in the corresponding period in 2016 primarily as a result2020, respectively, comprised of decreased workover expenses of $2.97 per BOE. In the comparative period in 2016, we deferred workover activity to the second half of the year due to low commodity prices. Excluding workover expenses, operating costs increased by $0.82 per BOE as discussed below.
In Colombia, operating costs for the three months ended September 30, 2017, decreased by $2.28 per BOE compared with the corresponding period in 2016, primarily as a result of decreased workover expenses of $3.16 per BOE. Excluding workover expenses, operating expenses in Colombia increased by $0.88 per BOE primarily as result of the NaturAmazonas reforestation and conservation program signed on January 30, 2017. After several months of planning and discussion, we signed an agreement with Conservation International to launch NaturAmazonas,a five year reforestation and conservation program to be implemented by Conservation International in the Putumayo Region of Colombia. Conservation International is a non-government organization, well-known for implementing and managing nature conservation projects around the world. During the three and nine months ended September 30, 2017, operating expenses included $0.8$1.0 million and $2.5$1.4 million respectively, related to this program.
As previously reported in our Quarterly Report on Form 10-Q filed with the SEC on August 4, 2017, since the Mocoa natural disaster, the electrical system in the Putumayo region has experienced instability,operating activities and we have had$0.1 million and $0.1 million related to utilize gas and diesel generators to maintain production and injection at key wells during brief periods of electrical outage. The instability of electricity not only increases our operating costs it also has a negative impact on our production in the Putumayo Basin and water injection program in both Costayaco and Moqueta. We are currently expanding a gas to electrical power facility in Costayaco which will enable consistent power generation. We expect the expanded facility to be in place by the end of 2017.
Operating expenses for the nine months ended September 30, 2017, increased by 26% to $78.5 million, compared with the corresponding period in 2016. The increase was due to higher sales volumes and increased operating costs per BOE. On a per BOE basis, operating expenses increased by 11% to $10.97 per BOE from $9.86 per BOE, in the corresponding period in 2016. Workover expenses decreased by $0.21 per BOE compared with the corresponding period in the prior year. Excluding workover expenses, operating costs increased by $1.32 per BOE primarily as a result of the NaturAmazonas reforestation and conservation program discussed above.
Colombian operating expenses for the nine months ended September 30, 2017, increased by $1.09 per BOE compared with the corresponding period in 2016. Workover expenses decreased by $0.23 per BOE. Excluding workover expenses, operating expenses in Colombia increased by $1.32 per BOE primarily as a result of increased costs and production disruptions in 2017, as described above.
Operating expenses were comparable totransportation activities. For the prior quarter, at $27.3COVID-19 costs were $0.9 million, in the three months ended September 30, 2017. On a per BOE basis,comprised of $0.8 million related to operating expenses decreased by $0.56and $0.1 million to $10.82 per BOE for the three months ended September 30, 2017, from $11.38 per BOE in the prior quarter primarily as a result of decreased workover expenses of $0.90 per BOE.transportation activities.
DD&A Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Three Months Ended June 30, | | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | | 2021 | 2020 |
DD&A Expenses, thousands of U.S. Dollars | $ | 38,055 | | $ | 31,340 | | | $ | 28,927 | | | $ | 98,300 | | $ | 131,118 | |
DD&A Expenses, U.S. Dollars per bbl | 17.36 | | 19.96 | | | 17.23 | | | 17.26 | | 23.48 | |
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Three Months Ended September 30, 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 | $ | 33,388 |
| $ | 13.22 |
| | $ | 34,156 |
| $ | 17.97 |
|
Brazil | — |
| — |
| | 1,022 |
| 13.47 |
|
Peru | 881 |
| — |
| | 206 |
| — |
|
Corporate | 223 |
| — |
| | 345 |
| — |
|
| $ | 34,492 |
| $ | 13.66 |
| | $ | 35,729 |
| $ | 18.08 |
|
| | | | | |
| Nine Months Ended September 30, 2017 | | Nine Months Ended September 30, 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 | $ | 88,453 |
| $ | 12.75 |
| | $ | 100,350 |
| $ | 16.37 |
|
Brazil | 2,263 |
| 10.69 |
| | 2,764 |
| 13.71 |
|
Peru | 1,350 |
| — |
| | 418 |
| — |
|
Corporate | 663 |
| — |
| | 993 |
| — |
|
| $ | 92,729 |
| $ | 12.97 |
| | $ | 104,525 |
| $ | 16.51 |
|
DD&A expenses for the three and nine months ended September 30, 2017, decreased2021, increased 21% and 25%, respectively, due to $34.5 million ($13.66 per BOE) and $92.7 million ($12.97 per BOE) from $35.7 million ($18.08 per BOE) and $104.5 million ($16.51 per BOE) inincreased production compared to the comparablecorresponding periods in 2016.of 2020. On a per BOEbbl basis, the decrease wasDD&A expenses decreased by $2.60 and $6.22 per bbl, respectively, due to lower costs in the depletable base and increased proved reserves.as a result of ceiling test impairment losses recorded over the last three quarters of 2020.
On a per BOE basis, DD&A expenses increased by 3% to $13.66 per BOE forFor the three months ended September 30, 2017, from $13.23 per BOE in2021, DD&A expenses increased 32% compared to the prior quarter due to higher costs in the depletable base from capital expendituresincreased production during the quarter ended September 30, 2017.current quarter. On a per bbl basis DD&A expenses were comparable to the previous quarter.
Impairment
Asset Impairmentimpairment
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | 2016 | | 2017 | 2016 |
Impairment of oil and gas properties | | | | | |
Colombia | $ | — |
| $ | 298,370 |
| | $ | — |
| $ | 431,146 |
|
Brazil | — |
| 21,604 |
| | — |
| 37,006 |
|
Peru | 176 |
| — |
| | 628 |
| 899 |
|
Mexico | 611 |
| — |
| | 611 |
| — |
|
| 787 |
| 319,974 |
|
| 1,239 |
| 469,051 |
|
Impairment of inventory | — |
| — |
| | — |
| 664 |
|
| $ | 787 |
| $ | 319,974 |
| | $ | 1,239 |
| $ | 469,715 |
|
Impairment losses in the comparative periods in 2016 in our Colombia and Brazil cost centers and inventory impairment were primarily due to lower oil prices. In accordance with GAAP, we used an average Brent price of $52.70 per bbl for the purposes of the September 30, 2017, ceiling test calculations (June 30, 2017 - $51.35, March 31, 2017 - $49.33; December 31, 2016 - $42.92; September 30, 2016 - $42.23; June 30, 2016 - $44.48, March 31, 2016 - $48.79; December 31, 2015 - $54.08).
We follow the full cost method of accounting for our oil(i) 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 our reserves.property impairment
G&A Expenses
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2017 | 2016 | % Change | | 2017 | 2016 | % Change |
G&A Expenses Before Stock-Based Compensation | $ | 7,610 |
| | $ | 6,965 |
| $ | 4,778 |
| 46 | | $ | 22,138 |
| $ | 16,414 |
| 35 |
G&A Stock-Based Compensation | 1,903 |
| | 1,686 |
| 814 |
| 107 | | 4,738 |
| 4,200 |
| 13 |
G&A Expenses, Including Stock-Based Compensation | $ | 9,513 |
| | $ | 8,651 |
| $ | 5,592 |
| 55 | | $ | 26,876 |
| $ | 20,614 |
| 30 |
| | | | | | | | | |
U.S. Dollars Per BOE Sales Volumes NAR |
|
| | | |
| |
|
|
|
|
|
G&A Expenses Before Stock-Based Compensation | $ | 3.18 |
| | $ | 2.76 |
| $ | 2.42 |
| 14 | | $ | 3.10 |
| $ | 2.60 |
| 19 |
G&A Stock-Based Compensation | 0.80 |
| | 0.67 |
| 0.41 |
| 63 | | 0.66 |
| 0.66 |
| — |
G&A Expenses, Including Stock-Based Compensation | $ | 3.98 |
| | $ | 3.43 |
| $ | 2.83 |
| 21 | | $ | 3.76 |
| $ | 3.26 |
| 15 |
G&A expenses before stock based compensation decreased by 8% compared with the prior quarter. For the three and nine months ended September 30, 2017,2021, we had no ceiling test impairment losses. For the three and nine months ended September 30, 2020, we had $104.7 million and $502.9 million of ceiling test impairment losses. We used an average Brent price of $60.12 and $47.95 per bbl for September 30, 2021 and 2020, respectively, ceiling test calculations.
(ii) Inventory impairment
For the three and nine months ended September 30, 2021, we had no inventory impairment. For the three and nine months ended September 30, 2020, we recorded $0.1 million and $4.2 million, respectively, of inventory impairment.
Goodwill impairment
The entire goodwill balance of $102.6 million was impaired during the nine months ended September 30, 2020, due to the unit's carrying value exceeding its fair value as a result of the impact of lower forecasted commodity prices.
G&A Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Three Months Ended June 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | 2020 | | | 2021 | | 2021 | 2020 | |
G&A Expenses Before Stock-Based Compensation | $ | 5,444 | | $ | 4,506 | | | | $ | 7,133 | | | $ | 18,475 | | $ | 17,183 | | |
G&A Stock-Based Compensation Expense (Recovery) | 1,053 | | 56 | | | | 1,873 | | | 6,597 | | (707) | | |
G&A Expenses, Including Stock-Based Compensation | $ | 6,497 | | $ | 4,562 | | | | $ | 9,006 | | | $ | 25,072 | | $ | 16,476 | | |
(U.S. Dollars Per bbl Sales Volumes NAR) | | | | | | | | | |
G&A Expenses Before Stock-Based Compensation | $ | 2.48 | | $ | 2.87 | | | | $ | 4.25 | | | $ | 3.24 | | $ | 3.08 | | |
G&A Stock-Based Compensation Expense (Recovery) | 0.48 | | 0.04 | | | | 1.12 | | | 1.16 | | (0.13) | | |
G&A Expenses, Including Stock-Based Compensation | $ | 2.96 | | $ | 2.91 | | | | $ | 5.37 | | | $ | 4.40 | | $ | 2.95 | | |
For the three and nine months ended September 30, 2021, G&A expenses before stock-based compensation increased by 46%21% and 35%8%, respectively, fromconsistent with an increase of operating activities in 2021 compared to the corresponding periods in 2016. The increase was commensurate with our growth. Since Juneof 2020. On a per bbl basis, for the three months ended September 30, 2016, we have completed two acquisitions, drilled 25 wells,2021, G&A expenses before stock-based compensation decreased by 14% to $2.48 as a result of higher sales volumes and grown production NAR 25% from 21,980 BOEPDincreased by 5% to $3.24 for the nine months ended September 30, 2021, as a result of increased operating activities when compared to the corresponding periods of 2020. For the three months ended September 30, 2021, G&A expenses before stock-based compensation decreased by 24% to $5.4 million or 42% to $2.48 on a per bbl basis compared to the prior quarter due to the timing of certain costs incurred and expensed in the third quarter of 2016 to 27,515 BOEPD in 2017.prior quarter.
AfterG&A expenses after stock-based compensation G&A expenses for the three and nine months ended September 30, 2017,2021, increased by 55% to $8.7 million ($3.4342% and 52% (2% and 49% per BOE) and by 30% to $26.9 million ($3.76 per BOE)bbl), respectively, from $5.6 million ($2.83 per BOE) and $20.6 million ($3.26 per BOE), respectively, incompared to the corresponding periods in 2016. The increase wasof 2020, mainly due to the increased head count.
higher stock-based compensation resulting from a higher share price. G&A expenses after stock-based compensation for the three months ended September 30, 2017,2021, decreased by 9% to $8.7 million ($3.4328% or 45% on a per BOE)bbl basis, compared with $9.5 million ($3.98 per BOE)the prior quarter, due to the timing of certain costs incurred and expensed in the prior quarter.
Equity Tax Expense
For the nine months ended September 30, 2017 and 2016, equity tax expense was $1.2 million and $3.1 million, respectively, and is a tax calculated based on our Colombian legal entities' balance sheets equity at January 1. The legal obligation for each year's equity tax liability arises on January 1 of each year; therefore, we recognize the annual amounts of the equity tax expense in our interim unaudited condensed consolidated statement of operations during the first quarter of each year.
Foreign Exchange Gains and Losses
For the three and nine months ended September 30, 2017,2021, we had a $2.7 million and $15.8 million, respectively, loss on foreign exchange gains of $1.3compared to a $4.3 million and losses of $0.8a $20.1 million respectively, compared with foreign exchange gains of $0.5 million and losses of $1.1 million, respectively, inloss for the corresponding periods in 2016. Under U.S. GAAP,of 2020. Accounts receivable, taxes receivable, deferred income taxes, accounts payable, and investment are considered a monetary liabilityitems and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation was the mainprimary source of the foreign exchange gains and losses. losses in the periods.
The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and nine months ended September 30, 2017,2021, and 2016:2020:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 | | 2021 | 2020 | | 2021 | 2020 |
Change in the U.S. dollar against the Colombian peso | weakened by | weakened by | | weakened by | weakened by | Change in the U.S. dollar against the Colombian peso | strengthened by | strengthened by | | strengthened by | strengthened by |
3% | 1% | | 2% | 9% | 2% | 3% | | 12% | 18% |
Change in the U.S. dollar against the Canadian dollar | | Change in the U.S. dollar against the Canadian dollar | strengthened by | weakened by | | strengthened by | strengthened by |
| 3% | 2% | | —% | 3% |
Financial Instrument Gains and Losses
The following table presents the nature of our derivative and other financial instruments gains and losses for the three and nine months ended September 30, 2017,2021, and 2016:
2020:
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | 2016 | | 2017 | 2016 |
Commodity price derivative loss (gain) | $ | 2,489 |
| $ | 2,190 |
| | $ | (3,759 | ) | $ | 856 |
|
Foreign currency derivatives gain | (814 | ) | (840 | ) | | (1,452 | ) | (1,958 | ) |
Trading securities loss | — |
| 701 |
| | — |
| 2,926 |
|
| $ | 1,675 |
| $ | 2,051 |
| | $ | (5,211 | ) | $ | 1,824 |
|
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | 2020 | | 2021 | 2020 |
Commodity price derivatives loss (gain) | $ | 2,586 | | $ | (2,206) | | | $ | 47,435 | | $ | (12,983) | |
Foreign currency derivatives loss | 17 | | 33 | | | 105 | | 3,566 | |
Derivative instruments loss (gain) | $ | 2,603 | | $ | (2,173) | | | $ | 47,540 | | $ | (9,417) | |
| | | | | |
Unrealized PetroTal investment (gain) loss | $ | (13,616) | | $ | 1,055 | | | $ | (17,477) | | $ | 60,124 | |
Loss on sale of PetroTal shares | — | | — | | | 5,070 | | — | |
Financial instruments (gain) loss | (18) | | 405 | | | (18) | | 1,162 | |
Other financial instruments (gain) loss | $ | (13,634) | | $ | 1,460 | | | $ | (12,425) | | $ | 61,286 | |
Income Tax Expense and Recovery
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2021 | 2020 | | 2021 | 2020 |
Income (loss) before income tax | $ | 43,962 | | $ | (128,386) | | | $ | 6,753 | | $ | (792,332) | |
| | | | | |
Current income tax expense (recovery) | $ | — | | $ | 637 | | | $ | (14) | | $ | 560 | |
Deferred income tax expense (recovery) | 8,955 | | (21,202) | | | 26,809 | | (62,796) | |
Total income tax expense (recovery) | $ | 8,955 | | $ | (20,565) | | | $ | 26,795 | | $ | (62,236) | |
| | | | | |
Effective tax rate | 20 | % | 16 | % | | 397 | % | 8 | % |
| | | | | |
| | | | | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(Thousands of U.S. Dollars) | 2017 | | 2016 | | 2017 | | 2016 |
Income (loss) before income tax | $ | 21,223 |
| | $ | (336,191 | ) | | $ | 59,280 |
| | $ | (492,732 | ) |
| | | | | | | |
Current income tax expense | $ | 4,333 |
| | $ | 3,879 |
| | $ | 13,522 |
| | $ | 11,680 |
|
Deferred income tax expense (recovery) | 13,760 |
| | (110,451 | ) | | 36,664 |
| | (166,202 | ) |
Total income tax expense (recovery) | $ | 18,093 |
| | $ | (106,572 | ) | | $ | 50,186 |
|
| $ | (154,522 | ) |
| | | | | | | |
Effective tax rate |
|
| |
|
| | 85 | % | | 31 | % |
| | | | | | | |
Deferred income tax recovery related to Colombia ceiling test impairment | $ | — |
| | $ | 119,348 |
| | $ | — |
| | $ | 172,458 |
|
Current income tax expense was higher in a recovery position for the threenine months ended September 30, 2017, compared with2021, versus an expense position for the correspondingcomparative period in 20162020, primarily as a resultdue to changes in the previous estimation of higher taxable income in Colombia.presumptive minimum tax. The deferred income tax expense of $13.8 million for the threenine months ended September 30, 2017, was primarily due to2021, resulted from excess tax depreciation compared with accounting depreciation and the use of tax losses to offset taxable income in Colombia. The deferred income tax recovery in the correspondingcomparative period in 2016 of $110.5 million included $119.3 million associated with2020 was mainly the result of a ceiling test impairment loss in Colombia, partially offset by losses incurred in Colombia. In 2016, the income tax recovery associated with impairment losses in Peru and Brazil wasColombia that are now fully offset by a full valuation allowance.
Current income tax expense was higher in the nine months ended September 30, 2017, compared with the corresponding period in 2016 as a result of higher taxable income in Colombia. The deferred income tax expense of $36.7 million for the nine months ended September 30, 2017, was primarily due to excess tax depreciation compared with accounting depreciation in Colombia. The deferred income tax recovery in the corresponding period in 2016 of $166.2 million included $172.5 million associated with ceiling test impairment losses in Colombia. In 2016, the income tax recovery associated with impairment losses in Peru and Brazil was offset by a full valuation allowance.
The effective tax rate was 85% in the nine months ended September 30, 2017, compared with 31% in the corresponding period in 2016. The increase in the effective tax rate for the nine months ended September 30, 2017, was primarily due to the impact of foreign taxes, foreign currency translation adjustments, non-deductible third-party royalty in Colombia and stock based compensation, which were partially offset by decreases in the valuation allowance, other permanent differences and other local taxes.
For the nine months ended September 30, 2017,2021, the difference between the effective tax rate of 85%397% and the 35% U.S. statutory31% Colombian tax rate was primarily due to the effectnon-deductibility of foreign taxes, valuation allowances, non-deductible third party royalty in Colombia, stock-based compensationderivative instrument losses and other local taxes. These items were partially offset byfinancing costs; foreign currency translation adjustments, and other permanent differences. stock based compensation. These were partially offset by a decrease in valuation allowance and the non-taxable portion (50%) of the unrealized gain on PetroTal Corp. ("PetroTal") shares.
In the third quarter of 2021, Congressional authorities in Colombia enacted a new tax legislation, which includes an increase to the corporate income tax rate to 35% from 31%, effective January 1, 2022. Accordingly, the tax rates applied to the calculation of deferred income taxes, before valuation allowances, have been adjusted to reflect this change.
For the nine months ended September 30, 2016,2020, the difference between the effective tax rate of 31%8% and the 35% U.S. statutory32% Colombian tax rate was primarily due to an increase toin the valuation allowance, which was largely attributable tothe non-deductibility of goodwill impairment losses in Brazil and Colombia, as well as non-deductible local taxes, stock based compensationfor tax purposes, foreign translation adjustments and the non-deductible third-party royalty in Colombia. These items were partially offset byportion (50%) of the impact of foreign taxes, foreign currency translation adjustments and other permanent differences. Other permanent differences mainly related to a non-taxable gain arisingunrealized loss on the acquisition of Petroamerica, partially offset by prior periods' true-up adjustments, uncertain tax position adjustments and other expenses deductible for tax.PetroTal shares.
Net Income and Funds Flow from Operations (a Non-GAAP Measure)
| | | | | | | | | | | | | | | | | | | | |
(Thousands of U.S. Dollars) | Third Quarter 2021 Compared with Second Quarter 2021 | % change | Third Quarter 2021 Compared with Third Quarter 2020 | % change | Nine Months Ended September 30, 2021 Compared with Nine Months Ended September 30, 2020 | % change |
Net loss for the comparative period | $ | (17,627) | | | $ | (107,821) | | | $ | (730,096) | | |
Increase (decrease) due to: | | | | | | |
Sales price | 9,162 | | | 61,106 | | | 150,930 | | |
Sales volumes | 29,534 | | | 21,071 | | | 3,460 | | |
Expenses: | | | | | | |
Operating | (12,136) | | | (16,846) | | | (7,950) | | |
Transportation | (100) | | | (1,735) | | | 101 | | |
Cash G&A | 1,689 | | | (938) | | | (1,292) | | |
Net lease payments | 47 | | | (70) | | | (107) | | |
Severance | — | | | 122 | | | 550 | | |
Interest, net of amortization of debt issuance costs | 340 | | | 490 | | | (1,243) | | |
Realized foreign exchange | 429 | | | 2,010 | | | (1,120) | | |
Cash settlements on derivative instruments | 16,973 | | | (2,959) | | | (55,011) | | |
Current taxes | (14) | | | 637 | | | 574 | | |
Other loss | — | | | (1,959) | | | (1,959) | | |
COVID-19 related costs | (93) | | | 118 | | | (1,497) | | |
Interest income | — | | | — | | | (345) | | |
Net change in funds flow from operations(1) from comparative period | 45,831 | | | 61,047 | | | 85,091 | | |
Expenses: | | | | | | |
Depletion, depreciation and accretion | (9,128) | | | (6,715) | | | 32,818 | | |
Goodwill impairment | — | | | — | | | 102,581 | | |
Asset impairment | — | | | 104,731 | | | 507,093 | | |
Deferred tax | 248 | | | (30,157) | | | (89,605) | | |
Amortization of debt issuance costs | (13) | | | (69) | | | 92 | | |
Stock-based compensation | 820 | | | (997) | | | (7,304) | | |
Derivative instruments gain or loss, net of settlements on derivative instruments | 1,663 | | | (1,817) | | | (1,946) | | |
Other financial instruments gain or loss | 16,248 | | | 15,094 | | | 73,711 | | |
Unrealized foreign exchange | (2,988) | | | (385) | | | 5,390 | | |
Other Loss | — | | | 2,026 | | | 2,026 | | |
Net lease payments | (47) | | | 70 | | | 107 | | |
Net change in net loss | 52,634 | | | 142,828 | | | 710,054 | | |
Net income (loss) for the current period | $ | 35,007 | | 299% | $ | 35,007 | | 132% | $ | (20,042) | | 97% |
|
| | | | | | | | | | | | | | | |
(Thousands of U.S. Dollars) | Third Quarter 2017 Compared with Second Quarter 2017 | % change | Third Quarter 2017 Compared with Third Quarter 2016 | % change | Nine Months Ended, September 30, 2017 Compared with Nine Months Ended September 30, 2016 | % change |
Net loss for the comparative period | $ | (6,807 | ) | | $ | (229,619 | ) | | $ | (338,210 | ) | |
Increase (decrease) due to: | | | | | | |
Prices | 2,285 |
| | 16,206 |
| | 71,333 |
| |
Sales volumes | 5,355 |
| | 19,023 |
| | 25,567 |
| |
Expenses: | | | | | | |
Operating | (113 | ) | | (1,683 | ) | | (16,013 | ) | |
Transportation | 454 |
| | (265 | ) | | 4,846 |
| |
Cash G&A and RSU settlements, excluding stock-based compensation expense | 784 |
| | (2,174 | ) | | (5,031 | ) | |
Transaction | — |
| | 6,088 |
| | 7,325 |
| |
Severance | (1,164 | ) | | (1,164 | ) | | 135 |
| |
Interest, net of amortization of debt issuance costs | (635 | ) | | (408 | ) | | (3,518 | ) | |
Realized foreign exchange | (107 | ) | | (3,004 | ) | | (2,461 | ) | |
Settlement of financial instruments | (146 | ) | | (136 | ) | | 1,080 |
| |
Current taxes | (2,561 | ) | | (454 | ) | | (1,842 | ) | |
Equity tax | — |
| | — |
| | 1,829 |
| |
Other | 56 |
| | (428 | ) | | (974 | ) | |
Net change in funds flow from operations(1) from comparative period | 4,208 |
| | 31,601 |
| | 82,276 |
| |
Expenses: |
|
| | | | |
Depletion, depreciation and accretion | (2,848 | ) | | 1,237 |
| | 11,796 |
| |
Asset impairment | (618 | ) | | 319,187 |
| | 468,476 |
| |
Deferred tax | (2,235 | ) | | (124,211 | ) | | (202,866 | ) | |
Amortization of debt issuance costs | (23 | ) | | 1,541 |
| | 945 |
| |
Stock-based compensation, net of RSU settlement | 78 |
| | (885 | ) | | (1,231 | ) | |
Financial instruments gain or loss, net of financial instruments settlements | (2,976 | ) | | 512 |
| | 5,955 |
| |
Unrealized foreign exchange | 5,275 |
| | 3,767 |
| | 2,741 |
| |
Loss on sale of Brazil business unit | 9,076 |
| | — |
| | (9,076 | ) | |
Gain on acquisition | — |
| | — |
| | (11,712 | ) | |
Net change in net income or loss | 9,937 |
| | 232,749 |
| | 347,304 |
| |
Net income for the current period | $ | 3,130 |
| 146 | % | $ | 3,130 |
| 101 | % | $ | 9,094 |
| 103 | % |
(1)Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operational Highlights—non-GAAP measures disclosure above regardingmeasures" for a definition and reconciliation of this measure.
2017 Capital Program
We expect the range of our projected 2017 capital program to be $225 million to $250 million. We expect to finance our 2017 capital program through cash flows from operations and available capacity under our credit facility, while retaining financial flexibility to undertake further development opportunities and opportunistically pursue acquisitions.
Capital expenditures during the three months ended September 30, 2017,2021 were $71.7$34.8 million:
| | | | | |
(Millions of U.S. Dollars) | |
Colombia: | |
Exploration | $ | 6.6 | |
Development: | |
Drilling and Completions | 9.6 | |
Facilities | 6.3 | |
Other | 11.8 | |
| 34.3 | |
Corporate & Ecuador | 0.5 | |
| $ | 34.8 | |
|
| | | |
(Thousands of U.S. Dollars) | |
Colombia | $ | 70,606 |
|
Peru | 998 |
|
Corporate | 90 |
|
| $ | 71,694 |
|
During the ninethree months ended September 30, 2017,2021, we drilledcommenced drilling the following wells in Colombia:
|
| | | | |
| Number of wells (Gross) | Number of wells (Net) |
Development | 15 |
| 11.6 |
|
Exploration | 4 |
| 2.6 |
|
Total Colombia | 19 |
| 14.2 |
|
| | | | | |
| Number of wells (Gross and Net) |
Development | 2.0 | |
| |
| |
The significant elements of our third quarter 2017 capital programWe spud two development wells in Colombia were:
On the Chaza Block (100% working interest ("WI"), operated), we successfully drilled Costayaco-30, a directional well targeting the Caballos formation, the U-Sand and A-Limestone in the northern portion of Costayaco field. Costayaco-30 completion work is underway.
On the Putumayo-7 Block (100% WI, operated), we completed the Cumplidor and Northwest 3-D seismic programs targeting the A-Limestone.
On the Midas Block, (100% WI, operated), we drilled, completed and brought on productionboth of which were producing as oil producers five development wells: Acordionero-12, Acordionero-13, Acordionero-15, Acordionero-17 and Mochuelo-1ST. We successfully completed a workover on the Mochuelo well targeting oil in the Lisama formation and source water for use in Acordionero waterflood. We also commenced drilling the Acordionero-18 and Acordionero-14i wells and completed water injection tests on Acordionero-8i.of September 30, 2021.
On the Putumayo-1 Block (55% WI, operated), we completed a production test at the Vonu-1 exploration well with successful production results.
On the Putumayo-4 Block (100% WI, operated), we started drilling the Siriri-1 exploration well.
On the Suroriente Block (15.8% WI, non-operated), we completed drilling the Cohembi-21 development well and commenced drilling the Cohembi-22 development well.
We continued facilities work at the Moqueta and Acordionero Fields.
Liquidity and Capital Resources
| | | | | | | | | | | | | | | | | |
| As at |
(Thousands of U.S. Dollars) | September 30, 2021 | | % Change | | December 31, 2020 |
Cash and Cash Equivalents | $ | 16,600 | | | 18 | | | $ | 14,114 | |
| | | | | |
| | | | | |
| | | | | |
Revolving Credit Facility | $ | 150,000 | | | (21) | | | $ | 190,000 | |
| | | | | |
6.25% Senior Notes | $ | 300,000 | | | — | | | $ | 300,000 | |
| | | | | |
7.75% Senior Notes | $ | 300,000 | | | — | | | $ | 300,000 | |
The outbreak of the COVID-19 virus, which was declared a pandemic by the World Health Organization in March 2020, spread across the globe and impacted worldwide economic activity. In 2020, global commodity prices declined significantly during the first half of 2020 due to disputes between major oil producing countries combined with the impact of the COVID-19 pandemic and associated reductions in global demand for oil. Governments worldwide, including those in Colombia and Ecuador, the countries where we operate, enacted emergency measures to combat the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods and social distancing, have caused, and may continue to cause, material disruption to businesses globally resulting in an economic slowdown. While global commodity prices have improved since historic lows during the first half of 2020, the current challenging economic climate had and may continue to have significant adverse impacts on our Company including, but not exclusively:
•material declines in revenue and cash flows as a result of the decline in commodity prices;
•declines in revenue and operating activities due to reduced capital programs and the shut-in of production;
•impairment charges;
•inability to comply with covenants and restrictions in debt agreements;
•inability to access financing sources;
•increased risk of non-performance by our customers and suppliers;
•interruptions in operations as we adjust personnel to the dynamic environment; and
|
| | | | | | | | | | |
| As at |
(Thousands of U.S. Dollars) | September 30, 2017 | | % Change | | December 31, 2016 |
Cash and Cash Equivalents | $ | 15,125 |
| | (40 | ) | | $ | 25,175 |
|
| | | | | |
Current Restricted Cash and Cash Equivalents | $ | 3,920 |
| | (53 | ) | | $ | 8,322 |
|
| | | | | |
Revolving Credit Facility | $ | 120,000 |
| | 33 |
| | $ | 90,000 |
|
| | | | | |
Convertible Senior Notes | $ | 115,000 |
| | — |
| | $ | 115,000 |
|
•inability to operate or delay in operations as a result COVID-19 restrictions in the countries in which we operate
Based on current forecasted Brent pricing and production levels, which can change materially in very short time frames, we forecasted to comply with the financial covenants contained in the revolving credit facility for at least the next year from the date of these financial statements. The amount available under our senior secured credit facility is based on the lender's borrowing base determination. The borrowing base is determined, by the lenders, based on our reserves and commodity prices. The next renewal of the borrowing base is in November 2021, and there is a risk that the lenders may reduce the borrowing base. In addition, our ability to borrow under the credit facility may be limited by the terms of the indentures for the 6.25% Senior Notes and 7.75% Senior Notes.
The risk of non-compliance with the covenants in the lending agreements and the risk associated with maintaining the borrowing base is heightened in the current period of volatility coupled with the unprecedented disruption caused by the COVID-19 pandemic. We believecurrently expect to continue to meet the terms of the credit facility or obtain further amendments or waivers if and when required. We also expect to maintain the borrowing base at a level in excess of the amount borrowed. However, there can be no assurances that our capital resources, including cashliquidity can be maintained at or above current levels during this period of volatility and global economic uncertainty.
The situation is dynamic, and the ultimate duration and magnitude of the impact on hand, cash generated from operationsthe economy and available capacitythe financial effect on our Company is not known at this time.
As at September 30, 2021, the borrowing base of our Senior Secured Credit Facility (the "revolving credit facility") was $215 million, with the next re-determination to occur no later than November 2021. We are required to comply with various covenants, which have been modified in response to the recent market conditions and the COVID-19 pandemic. We have obtained relief from compliance with certain financial covenants, which expired on October 1, 2021 ("the covenant relief period"). During the covenant relief period, our ratio of total debt to EBITDAX was permitted to be greater than 4.0 to 1.0, our Senior Secured Debt to EBITDAX ratio could not exceed 2.5 to 1.0, and our EBITDAX to interest expense ratio for the trailing four-quarter periods measured as of the last day of the fiscal quarters ending as of the last day of the fiscal quarters ended September 30, 2021, was required to be at least 2.0 to 1.0. We are required to comply with various covenants, which as disclosed above, have been modified in response to the current market conditions and the COVID-19 pandemic. As of September 30, 2021, we were in compliance with all applicable covenants in the revolving credit facility.
After the expiration of the covenant relief period on October 1, 2021, we must maintain compliance with the following financial covenants: limitations on our ratio of debt to EBITDAX to a maximum of 4.0 to 1.0; limitations on our ratio of Senior Secured Debt to EBITDAX to a maximum of 3.0 to 1.0; and the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. If we fail to comply with these financial covenants, it would result in a default under the terms of the credit agreement, which could result in an acceleration of repayment of all indebtedness under the Company's revolving credit facility.
Amounts drawn under the revolving credit facility will providebear interest, at the borrower's option, USD LIBOR plus a margin ranging from 2.90% to 4.90%, or base rate plus a margin ranging from 1.90% to 3.90%, in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. We pay a commitment fee on undrawn amounts under the revolving credit facility, which ranges from 0.73% to 1.23% per annum, based on the average daily amount of unused commitments.
At September 30, 2021, we had $150.0 million drawn under the revolving credit facility. During the third quarter of 2021, we repaid $25.0 million of the amount drawn under the revolving credit facility. Accordingly, we had $65.0 million of availability under the revolving credit facility as of September 30, 2021. As of October 29, 2021, outstanding borrowings under our revolving credit facility were further reduced to $130.0 million.
At September 30, 2021, we had a $300.0 million aggregate principal amount of 6.25% Senior Notes due 2025 and a $300.0 million aggregate principal amount of 7.75% Senior Notes due 2027 outstanding. An event of default under the revolving credit facility would result in a default under the indentures governing the senior notes, which could allow the noteholders to require us with sufficient liquidity to meet our strategic objectives and planned capital program for 2017, given current oil price trends and production levels. repurchase all of the outstanding Senior Notes.
In accordance with our investment policy, available cash balances are held in our primary cash management banks in interest earning current accounts or may be invested in U.S. or Canadian government-backed federal, provincial, or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions.
Derivative Positions
At September 30, 2017, we had a revolving credit facility with a syndicate of lenders with a borrowing base of $300 million. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. As a result of the semi-annual redetermination of the committed borrowing base under our revolving credit facility, the committed borrowing base was increased from $250 million to $300 million effective June 1, 2017. The next re-determination of the borrowing base is due to occur no later than November 2017. On September 18, 2017, we entered into the Eighth Amendment to our credit agreement with the other parties thereto, which, among other things, extended the maturity date of the borrowings under the revolving credit facility from September 18, 2018 to October 1, 2018. Subject to documentation, the maturity date of the borrowings under the revolving credit facility is expected to be further extended to November 2020 and the borrowing base is expected to be confirmed at $300 million until May 2018.
Under the terms of our credit facility, we are required to maintain compliance with certain financial and operating covenants which include: the maintenance of a ratio of debt, including letters of credit, to net income plus interest, taxes, depreciation, depletion, amortization, exploration expenses and all non-cash charges minus all non-cash income (as defined in our credit agreement, "EBITDAX") not to exceed 4.00 to 1.0; the maintenance of a ratio of senior secured obligations to EBITDAX not to exceed 3.00 to 1.00; and the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. As at September 30, 2017, we were in compliance with all financial and operating covenants in our credit agreement. Under the terms of the credit facility, we are limited in our ability to pay any dividends to our shareholders without bank approval.
The 5.00% Convertible Senior Notes due 2021, will mature on April 1, 2021, unless earlier redeemed, repurchased or converted.
Cash and Cash Equivalents Held Outside of Canada and the United States
At September 30, 2017, 97% of our cash and cash equivalents were held by subsidiaries and partnerships outside of Canada and the United States. This cash was generally not available to fund domestic or head office operations unless funds were repatriated. At this time, we do not intend to repatriate further funds other than to pay head office charges, but if we did, we might have to accrue and pay withholding taxes in certain jurisdictions on the distribution of accumulated earnings. Undistributed earnings of foreign subsidiaries are considered to be permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.
In Colombia, we participate in a special exchange regime, and we receive revenue in U.S. dollars offshore. We may also pay invoices denominated in U.S. dollars for our Colombian business from these U.S. dollars received offshore. In Peru, expenditures may be paid in local currency or U.S. dollars.
Derivative Positions
At September 30, 2017, we had outstanding commodity price derivative positions as follows:
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| | | | | | | | | | | | |
Period and type of instrument | Volume, bopd | Reference | Sold Put ($/bbl) | Purchased Put ($/bbl) | Sold Call ($/bbl) |
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 |
|
| | | | | | | | | | | | | | | | | | | | |
Period and type of instrument | Volume, bopd | Reference | Sold Put ($/bbl, Weighted Average) | Purchased Put ($/bbl, Weighted Average) | Sold Call ($/bbl, Weighted Average) | Swap Price ($/bbl, Weighted Average) |
Three-way Collars: October 1, to December 31, 2021 | 7,000 | | ICE Brent | 47.14 | | 57.14 | | 68.95 | | n/a |
Swaps: October 1, to December 31, 2021 | 3,000 | | ICE Brent | n/a | n/a | n/a | 56.75 | |
Subsequent to September 30, 2017, we entered into the following commodity price contracts:Foreign Currency Derivatives
|
| | | | | | | | | |
Period and type of instrument | Volume, bopd | Reference | Purchased Swap ($/bbl) | Purchased Call ($/bbl) |
Swap: January 1, to December 31, 2018 | 2,500 |
| ICE Brent | $ | 55.75 |
| |
Swap: January 1, to December 31, 2018 | 2,500 |
| ICE Brent | $ | 56.05 |
| |
Participating Swap: January 1, to December 31, 2018 | 2,500 |
| ICE Brent | $ | 50.00 |
| $ | 54.10 |
|
At September 30, 2017,2021, we had the following outstanding foreign currency derivative positions:positions as follows:
| | | | | | | | | | | | | | | | | |
Period and type of instrument | Amount Hedged (Millions COP) | U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1) | Reference | Floor Price (COP, Weighted Average) | Cap Price (COP, Weighted Average) |
Collars: October 1, to December 31, 2021 | 3,000 | 782 | COP | 3,500 | 3,630 |
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| | | | | | | | | |
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: October 1, 2017 to October 31, 2017 | 23,000 |
| 7,832 |
| COP | 3,000 |
| 3,117 |
|
Collar: November 1, 2017 to November 30, 2017 | 25,000 |
| 8,513 |
| COP | 3,000 |
| 3,139 |
|
Collar: December 1, 2017 to December 28, 2017 | 25,000 |
| 8,513 |
| COP | 3,000 |
| 3,142 |
|
| 73,000 |
| 24,858 |
| | | |
(1) At September 30, 20172021 foreign exchange rate.
Subsequent toAt September 30, 2017,2021, our balance sheet included $14.7 million of current liabilities related to the we entered into the followingabove outstanding commodity price and foreign currency contracts:derivative positions.
|
| | | | | | | | | |
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: January 1, 2018 to December 31, 2018 | 132,000 |
| 44,949 |
| COP | 3,000 |
| 3,112 |
|
Cash Flows
The following table presents our primary sources and uses of cash and cash equivalents for the periods presented:
|
| | | | | | |
| Nine Months Ended September 30, |
| 2017 | 2016 |
Sources of cash and cash equivalents: | | |
Net income (loss) | $ | 9,094 |
| $ | (338,210 | ) |
Adjustments to reconcile net income (loss) to funds flow from operations | | |
DD&A expenses | 92,729 |
| 104,525 |
|
Asset impairment | 1,239 |
| 469,715 |
|
Deferred tax expense (recovery) | 36,664 |
| (166,202 | ) |
Stock-based compensation expense | 4,935 |
| 4,380 |
|
Amortization of debt issuance costs | 1,868 |
| 2,813 |
|
Cash settlement of RSUs | (534 | ) | (1,210 | ) |
Unrealized foreign exchange (gain) loss | (304 | ) | 2,437 |
|
Financial instruments (gain) loss | (5,211 | ) | 1,824 |
|
Cash settlement of financial instruments | 1,518 |
| 438 |
|
Loss on sale of Brazil business unit | 9,076 |
| — |
|
Gain on acquisition | — |
| (11,712 | ) |
Funds flow from operations | 151,074 |
| 68,798 |
|
Proceeds from bank debt, net of issuance costs | 115,264 |
| 220,169 |
|
Proceeds from sale of Brazil business unit, net of cash sold | 34,481 |
| — |
|
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit | 4,700 |
| — |
|
Changes in non-cash investing working capital | 11,347 |
| — |
|
Net changes in assets and liabilities from operating activities | — |
| 18,097 |
|
Proceeds from sale of marketable securities | — |
| 788 |
|
Proceeds from issuance of subscription receipts, net of issuance costs | — |
| 165,805 |
|
Proceeds from issuance of Notes, net of issuance costs | — |
| 109,090 |
|
Proceeds from issuance of shares | — |
| 5,169 |
|
| 316,866 |
| 587,916 |
|
| | |
Uses of cash and cash equivalents: | | |
Additions to property, plant and equipment | (175,719 | ) | (69,667 | ) |
Additions to property, plant and equipment - property acquisitions | (30,410 | ) | (19,388 | ) |
Repayment of bank debt | (85,000 | ) | (110,181 | ) |
Repurchase of shares of Common Stock | (10,000 | ) | — |
|
Net changes in assets and liabilities from operating activities | (28,105 | ) | — |
|
Changes in non-cash investing working capital | — |
| (8,036 | ) |
Settlement of asset retirement obligations | (462 | ) | (496 | ) |
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents | (1,060 | ) | (452 | ) |
Acquisition of Petroamerica, net of cash acquired | — |
| (457,183 | ) |
| (330,756 | ) | (665,403 | ) |
Net decrease in cash and cash equivalents and restricted cash and cash equivalents | $ | (13,890 | ) | $ | (77,487 | ) |
| | | | | | | | |
| Nine Months Ended September 30, |
(Thousands of U.S. Dollars)
| 2021 | 2020 |
Sources of cash and cash equivalents: | | |
Net loss | $ | (20,042) | | $ | (730,096) | |
Adjustments to reconcile net loss to Adjusted EBITDA(1) and funds flow from operations(1) | | |
DD&A expenses | 98,300 | | 131,118 | |
Interest expense | 41,355 | | 40,204 | |
Income tax expense (recovery) | 26,795 | | (62,236) | |
Goodwill impairment | — | | 102,581 | |
Asset impairment | — | | 507,093 | |
Other loss | — | | 2,026 | |
Non-cash lease expenses | 1,222 | | 1,494 | |
Lease payments | (1,239) | | (1,404) | |
Unrealized foreign exchange loss | 16,945 | | 22,335 | |
Stock-based compensation expense (recovery) | 6,597 | | (707) | |
Unrealized derivative instruments loss | 2,499 | | 553 | |
Other financial instruments (gain) loss | (12,425) | | 61,286 | |
Adjusted EBITDA(1) | 160,007 | | 74,247 | |
Current income tax recovery (expense) | 14 | | (560) | |
Contractual interest and other financing expenses | (38,673) | | (37,430) | |
Funds flow from operations(1) | 121,348 | | 36,257 | |
Proceeds from debt, net of issuance costs | — | | 88,382 | |
Proceeds from issuance of Senior Notes, net of issuance costs | — | | — | |
Proceeds from issuance of exercise of stock options | 19 | | — | |
Proceeds from disposition of investment, net of transaction costs | 14,632 | | — | |
Net changes in assets and liabilities from operating activities | 17,956 | | 23,288 | |
Changes in non-cash investing working capital | 709 | | — | |
| 154,664 | | 147,927 | |
| | |
Uses of cash and cash equivalents: | | |
Additions to property, plant and equipment | (109,650) | | (56,378) | |
| | |
Repayment of debt | (40,000) | | (7,000) | |
| | |
| | |
Debt issuance costs | (125) | | — | |
| | |
Changes in non-cash investing working capital | — | | (69,549) | |
Settlement of asset retirement obligations | (483) | | (199) | |
Lease payments | (1,269) | | (307) | |
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents | (528) | | (754) | |
| (152,055) | | (134,187) | |
Net increase in cash and cash equivalents and restricted cash and cash equivalents | $ | 2,609 | | $ | 13,740 | |
Cash provided by operating activities in the nine months ended September 30, 2017, was primarily affected by higher(1) Adjusted EBITDA and funds flow from operations (seeare a non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operational Highlights - non-GAAP measures” for a definition and reconciliation of net income (loss) to funds flow from operations under the heading 'Financial and Operational Highlights' above) and a $28.1 million change in assets and liabilities from operating activities.this measure.
One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices, the impact of which we partially mitigate by entering into commodity price derivatives. Sales volume changes and costs related to operations and debt service also impact cash flow.flows. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes, the impact of which we partially mitigate by entering into foreign currency derivatives. During the nine months ended September 30, 2021, funds flow from operations increased by 235% compared to the corresponding period of 2020 primarily due to a significant increase in Brent price and increase in production, which were offset by an increase in operating expenses and cash settlements on derivative instruments.
Off-Balance Sheet Arrangements
As at September 30, 2017,2021, we had no off-balance sheet arrangements.
Contractual Obligations
During the nine months endedAt September 30, 2017,2021, we borrowed a net amount of $30.3had $150.0 million ondrawn under our revolving credit facility. Additionally, at June 30, 2017, we sold our Brazil business unit and its related obligations.
Except asfor noted above, as at September 30, 2017,2021, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as at December 31, 2016.2020.
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates are disclosed in Item 7 of our 20162020 Annual Report on Form 10-K filed with the SEC on March 1, 2017, and have not changed materially since the filing of that document, other than as follows:document.
Full Cost Method of Accounting and Impairments of Oil and Gas Properties
In the nine months ended September 30, 2017, we had no ceiling test impairment losses in our Colombia and Brazil cost centers. We used an average Brent price of $52.70 per bbl for the purposes of the September 30, 2017 ceiling test calculations (June 30, 2017 - $51.35, March 31, 2017 - $49.33; December 31, 2016 - $42.92; September 30, 2016 - $42.23; June 30, 2016 - $44.48, March 31, 2016 - $48.79; December 31, 2015 - $54.08).
Holding all factors constant other than benchmark oil prices, it is reasonably likely that we will not experience ceiling test impairment losses in our Colombia cost center in the fourth quarter of 2017. It is difficult to predict with reasonable certainty the amount of expected future impairment losses given the many factors impacting the asset base and the cash flows used in the prescribed U.S. GAAP ceiling test calculation. These factors include, but are not limited to, future commodity pricing, royalty rates in different pricing environments, operating costs and negotiated savings, foreign exchange rates, capital expenditures timing and negotiated savings, production and its impact on depletion and cost base, upward or downward reserve revisions as a result of ongoing exploration and development activity, and tax attributes.
Subject to these factors and inherent limitations, we do not believe that ceiling test impairment losses will be experienced in the fourth quarter of 2017. The calculation of the impact of higher commodity prices on our estimated ceiling test calculation was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of benchmark oil prices. Therefore, this calculation strictly isolates the impact of commodity prices on the prescribed GAAP ceiling test. This calculation was based on a pro forma Brent oil price of $54.16 per bbl for the year ended December 31, 2017. This pro forma oil price was calculated using a 12-month unweighted arithmetic average of oil prices, and included the oil prices on the first day of the month for the ten months ended October 31, 2017, and, for the two months ended December 31, 2017, estimated oil prices for the fourth quarter of 2017 using the forward price curve forecast from Bloomberg dated September 30, 2017.
As noted above, actual cash flows may be materially affected by other factors. For example, in Colombia, cash royalties are levied at lower rates in low oil price environments and foreign exchange rates can materially impact the deferred tax component of the asset base, operating costs, and the income tax calculation.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity price risk
Our principal market risk relates to oil prices. Oil prices are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Most of our revenues are from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to West Texas Intermediate ("WTI") or Brent and adjusted for quality each month.
We have entered into commodity price derivative contracts to manage the variability in cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending.
Foreign currency risk
Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 100% of our revenues are related to the U.S. dollar price of Brent or WTI oil. In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. In Peru, capital expenditures are based on U.S. dollar prices and may be paid in local currency or U.S. dollars. The majority of income and value added taxes and G&A expenses in Colombia and Peru are in local currency. Certain G&A expenses incurred at our head office in Canada are denominated in Canadian dollars. While we operate in South America exclusively, the majority of our acquisition expenditures have been valued and paid in U.S. dollars.
Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our current and deferred tax liabilities, which are monetary liabilities, denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain or loss must be calculated on conversionSmaller Reporting Company, we are not required to the U.S. dollar functional currency.provide information under this Item 3.
We have entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our revolving credit facility, which bears floating rates of interest. At September 30, 2017, our outstanding revolving credit facility was $120.0 million (December 31, 2016 - $90.0 million), which had a weighted-average interest rate of approximately 3.5%. A 10% change in LIBOR would not materially impact our interest expense on debt outstanding at September 30, 2017.
Further information
See Note 10 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for further information regarding our derivative contracts, including the notional amounts and call and put prices by expected (contractual) maturity dates. Expected cash flows from the derivatives equaled the fair value of the contract. The information is presented in U.S. dollars because that is our reporting currency. We do not hold any of these derivative contracts for trading purposes.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, includingwith the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(b) of the Exchange Act. Based on theirthis evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra's disclosure controls and procedures were effective as of September 30, 2017.2021.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended September 30, 2017,2021, that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.
PART II - Other Information
Item 1. Legal Proceedings
See Note 911 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for any material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2016,2020, and any material matters that have arisen since the filing of such report.
Item 1A. Risk Factors
SeeThere are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to information set forth in this quarterly report on Form 10-Q, including in Part I, Item 1A Risk Factors2 "Management's Discussion and Analysis of our 2016 Annual Report on Form 10-K. The risks facing our company have not changed materially from thoseFinancial Condition and Results of Operations", you should carefully read and consider the factors set forthout in Part I, Item 1A Risk Factors of"Risk Factors" in our 2016 Annual Report on Form 10-K.10-K for the year ended December 31, 2020. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of the current pandemic and downturn in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 6. Exhibits
| | | | | | | | | | | |
Exhibit No. | Description | | Reference |
| | | |
Exhibit No. | Description | | Reference |
2.1+3.1 | | | Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on November 18, 2015 (SEC File No. 001-34018). |
| | | |
2.2 | | | Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018). |
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3.1 | | | Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018). |
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3.2 | | | Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018). |
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4.13.3 | | | |
| | | |
4.2 | | | Incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005, and filed with the SEC on April 21, 2006 (SEC File No. 333-111656). |
| | | |
4.3 | | | Incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the SEC on April 21, 2006 (SEC File No. 333-111656). |
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4.4 | | | Incorporated by reference to Annex E to the Proxy Statement on Schedule 14A filed with the SEC on October 14, 2008 (SEC File No. 001-34018). |
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4.5 | | | Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018). |
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4.6 | | | Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018). |
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4.7 | | | Incorporated by reference to Exhibit 4.13.1 to the Current Report on Form 8-K filed with the SEC on July 14, 20169, 2018 (SEC File No. 001-34018). |
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4.83.4 | | | Incorporated by reference to Exhibit 4.23.1 to the Current Report on Form 8-K filed with the SEC on July 14, 2016August 4, 2021 (SEC File No. 001-34018). |
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10.131.1 | | | Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on September 21, 2017 (SEC File No. 001-34018).
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10.2 | | | Filed herewith. |
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12.1 | | | Filed herewith. |
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31.1 | | | Filed herewith. |
| | | |
31.2 | | | Filed herewith. |
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32.1 | | | Furnished herewith. |
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH Inline XBRL Taxonomy Extension Schema Document
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document
+ Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K.104.The cover page from Gran Tierra undertakes to furnish supplemental copies of any ofEnergy Inc.'s Quarterly Report on Form 10-Q for the omitted schedules upon request byquarter ended September 30, 2021, formatted in Inline XBRL (included within the SEC.Exhibit 101 attachments).
*Management contract or compensatory plan or arrangement
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
GRAN TIERRA ENERGY INC.
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| | | | | | | |
Date: November 2, 20173, 2021 | | /s/ Gary S. Guidry |
| | By: Gary S. Guidry |
| | President and Chief Executive Officer |
| | (Principal Executive Officer) |
|
| | | | | | | |
Date: November 2, 20173, 2021 | | /s/ Ryan Ellson |
| | By: Ryan Ellson |
| | Executive Vice President and Chief Financial Officer |
| | (Principal Financial and Accounting Officer) |