GRAN TIERRA ENERGY INC. This report, and in particular this Management's Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Please see the cautionary language at the very beginning of this Annual Report on Form 10-K regarding the identification of and risks relating to forward-looking statements, as well as Part I, Item 1A. "Risk Factors" in this Annual Report on Form 10-K. The following discussion of our financial condition and results of operations should be read in conjunction with the "Financial Statements and Supplementary Data" as set out in Part II, Item 8 of this Annual Report on Form 10-K.
Overview
We are a company focused on oil and gas exploration and production inColombia andEcuador . Our Colombian properties represented 100% of our proved reserves NAR atDecember 31, 2019 . For the year endedDecember 31, 2019 , 100% of our revenue was generated inColombia (year endedDecember 31, 2018 - 100%; year endedDecember 31, 2017 - 98%). We are headquartered inCalgary, Alberta, Canada .
As of
As discussed under Items 1 and 2. "Business and Properties," in 2019, we completed certain asset acquisitions to further enhance our strategy.
Financial and Operational Highlights
Key Highlights
Operational Highlights: • Increase proved oil and gas reserves by 26% and achieved a proven reserve
replacement ratio of 226%
• Announced a new country entry into
100% WI in three highly prospective exploration blocks via successful bids
in a bidding round, creating a contiguous acreage position extending from
our existing assets in the Colombian Putumayo Basin
• Our total 2019 average production NAR was 29,015 BOEPD, comparable with
2018. Production was negatively impacted by downtime from electricalsubmersible pump ("ESP") failures in Acordionero and the temporary shut-in
of several wells in Acordionero with high gas oil ratio ("GOR"). The
successful commissioning of water injection facilities in Acordionero in
reduced gas production in Acordionero from a high of 18 mmcf down to the
current 8 mmcf per day, all of which is either consumed to generate power
or re-injected into the reservoir
• Our total 2019 oil and gas sales volumes NAR increased by 1% to 29,140
BOEPD compared with 2018
29--------------------------------------------------------------------------------
Financial Highlights:
• Net income in 2019 was
compared to net income of $102.6 million , or $0.26 per share basic and
diluted in 2018
• Net income before taxes in 2019 was
million in 2018
• EBITDA(1) was
• Adjusted EBITDA(1) was$325.9 million compared with$375.9 million in 2018 • Returned$37.6 million to shareholders through the repurchase of 20,097,471 common shares • Oil and gas sales for 2019 decreased 7% to$571.0 million compared with$613.4 million in 2018
• Funds flow from operations(1) decreased by 11% to
per share basic and diluted) compared with
basic and diluted) in 2018, consistent with the average Brent price
decreasing 11% from 2018
• Oil and gas sales per BOE for 2019 were
• Operating expenses per BOE for 2019 were
2018 primarily as a result of higher power generation and rental costs.
With the commissioning of the production facilities and the gas to power
project in Acordionero both total and per BOE operating costs are expected
to decrease in 2020.
• Workover expenses per BOE for 2019 increased by 18% to
2018 primarily as a result of higher frequency of ESP failures during 2019
due to power outages. With the commissioning of the gas- to-power project
which has resulted in more reliable power, we are expecting lower workover
costs in 2020.
• Quality and transportation discounts per BOE for 2019 was
to
contracts which had lower quality and transportation discounts compared to
the sales contracts used for in 2018
• Transportation expenses per BOE for 2019 decreased by 31% to $1.92
compared with 2018, due to a higher percentage of volumes being sold at
wellhead where transportation is netted against sales price
• General and administrative ("G&A") expenses before stock-based
compensation per BOE for 2019 increased by 5% to
2018
• On
("7.75% Senior Notes")
• We purchased and canceled
Convertible Senior Notes due 2021 ("Convertible Notes")
• In November, 2019, we extended the maturity of our credit facility to
November 10, 2022 Environmental, Social and Governance Highlights: • In 2019, we achieved our best safety record in terms of Lost Time Injuries
('LTI") and Total Recordable Injuries; our 2019 LTI ratio of 0.02 was 80%
below the industry average for Latin American exploration and production
companies, which was reported by the
Gas Producers in 2019
• In partnership with the international non-governmental organization
land and securing and maintaining 18,000 hectares of forest through the
NaturAmazonas project in the
investment in the Andes-Amazon rainforest corridor through this project is
forecasted to be $13 million
• We planted a total of 560,112 trees and have conserved, preserved or
reforested 1,367 hectares of land through all of our environmental efforts
• For the last 4 years, we have voluntarily released an assessment of ourgreenhouse gas ("GHG") emissions
• We are reducing GHG emissions at our facilities through gas-to-power
projects by converting excess natural gas, that would otherwise be flared,
and using it instead for power generation; in 2019, we completed a
gas-to-power project at the Acordionero Field, ours single biggest
producing asset; previously, gas-to-power projects were completed at the
Moqueta field in 2018 and the Costayaco field in 2017
• We are working to eliminate all routine flaring in our operations
• We are undertaking the NaturAmazonas project over the course of seven
years, commencing in 2017. This project alone is expected to sequester
approximately 8.7 million tons of CO2 over its lifetime
• We have created almost 16,000 local labor opportunities over the past 3 years
30--------------------------------------------------------------------------------
(Thousands ofU.S. Dollars, unless otherwise noted) Year Ended December 31, SEC Compliant Reserves, NAR 2019 % Change 2018 % Change 2017 (MMBOE)Estimated Proved Oil and Gas Reserves 68 26 54 (8 ) 59Estimated Probable Oil and Gas Reserves 58 (6 ) 62 13 55Estimated Possible Oil and Gas Reserves 38 (22 ) 49 (16 ) 58Average Consolidated Daily Volumes (BOEPD) Working Interest Production Before Royalties(2) 34,817 (4 ) 36,209 13 32,105 Royalties (5,802 ) (19 ) (7,156 ) 35 (5,320 ) Production NAR 29,015 - 29,053 8 26,785 Decrease (Increase) in Inventory 125 (137 ) (336 ) 250 (96 ) Sales(3) 29,140 1 28,717 8 26,689 Net Income (Loss)$ 38,690 (62 )$ 102,616 424$ (31,708 ) Operating Netback Oil and Natural Gas Sales$ 570,983 (7 )$ 613,431 45$ 421,734 Operating Expenses (142,086 ) 28 (111,272 ) 27 (87,855 ) Workover Expenses (41,118 ) 19 (34,437 ) 56 (22,014 ) Transportation Expenses (20,400 ) (30 ) (28,993 ) 15 (25,107 ) Operating Netback(1)$ 367,379 (16 )$ 438,729 53$ 286,758 G&A Expenses Before Stock-Based Compensation$ 33,300 6$ 31,369 5$ 29,775 G&A Stock-Based Compensation$ 1,430 (82 )$ 8,114 (12 )$ 9,239 EBITDA(1)$ 364,276 (3 )$ 376,718 106$ 182,547 Funds Flow From Operations(1)$ 272,409 (11 )$ 306,449 39$ 220,197 Capital Expenditures$ 379,314 9$ 347,093 38$ 251,041 Net Cash Received on Dispositions $ - - $ -
(100 )
Cash Paid for Acquisitions, Net of Cash Acquired$ 77,772 46$ 53,200 55$ 34,410 As at December 31, (Thousands of U.S. Dollars) 2019 % Change 2018 % Change 2017 Cash, Cash Equivalents and Current Restricted Cash and Cash Equivalents$ 8,817 (83 )$ 52,309 117$ 24,113 Revolving Credit Facility$ 118,000 100 $ - (100 )$ 148,000 Senior Notes$ 600,000 100$ 300,000 100 $ - Convertible Notes $ - (100 )$ 115,000 -$ 115,000 (1) Non-GAAP measures Operating netback, EBITDA, funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net income or loss or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from
31
--------------------------------------------------------------------------------
other companies and, accordingly, may not be comparable to similar measures used
by other companies. Each non-GAAP financial measure is presented along with the
corresponding GAAP measure so as not to imply that more emphasis should be
placed on the non-GAAP measure.
Operating netback, as presented, is defined as oil and natural gas sales less
operating, workover and transportation expenses. Management believes that
operating netback is a useful supplemental measure for management and investors
to analyze financial performance and provides an indication of the results
generated by our principal business activities prior to the consideration of
other income and expenses. A reconciliation from oil and natural gas sales to
operating netback is provided in the table above.
EBITDA, as presented, is defined as net income or loss adjusted for depletion,
depreciation and accretion ("DD&A") expenses, interest expense and income tax
expense. Adjusted EBITDA, as presented is defined as EBITDA adjusted for loss on
redemption of Convertible Notes, investment gains or losses, loss on sale of
business units and asset impairment. Management uses this supplemental measure
to analyze performance and income generated by our principal business activities
prior to the consideration of how non-cash items affect that income, and
believes that this financial measure is useful supplemental information for
investors to analyze our performance and our financial results. A reconciliation
from net income to EBITDA and adjusted EBITDA is as follows:
Year Ended December 31,
(Thousands of U.S. Dollars) 2019 2018
2017
Net Income (loss)$ 38,690 $ 102,616 $ (31,708 ) Adjustments to reconcile net income (loss) to EBITDA and adjusted EBITDA DD&A expenses 225,033 197,867 131,335 Interest expense 43,268 27,364 13,882 Income tax expense 57,285 48,871 69,038 EBITDA (non-GAAP)$ 364,276 $ 376,718 $ 182,547 Loss on redemption of Convertible Notes 11,501 - - Investment gain (49,884 ) (786 ) (111 ) Loss on sale of business units - - 44,385 Asset impairment - - 1,514 Adjusted EBITDA (non-GAAP)$ 325,893 $ 375,932 $ 228,335 Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, asset impairment, deferred tax expense, stock-based compensation expense, amortization of debt issuance costs, non-cash lease expense, lease payments, cash settlement of RSUs, unrealized foreign exchange gains or losses, financial instruments gains or losses, cash settlement of financial instruments and loss on redemption of Convertible Notes. Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income or loss to funds flow from operations is as follows: Year Ended December
31,
(Thousands of U.S. Dollars) 2019 2018
2017
Net Income (loss)$ 38,690 $ 102,616 $ (31,708 ) Adjustments to reconcile net income (loss) to funds flow from operations DD&A expenses 225,033 197,867 131,335 Asset impairment - - 1,514 Deferred tax expense 40,227 4,968 44,716 Stock-based compensation expense 1,430 8,299
9,775
Amortization of debt issuance costs 3,376 3,183 2,415 Non-cash lease expense 1,806 - - Lease payments (1,969 ) - - Cash settlement of RSUs - (360 ) (564 ) Unrealized foreign exchange loss 1,803 11,511
837
Financial instruments (gain) loss (46,215 ) 12,296
15,929
Cash settlement of financial instruments (3,273 ) (33,931 )
1,563
Loss on redemption of Convertible Notes 11,501 -
44,385
Funds flow from operations (non-GAAP)
(2)Includes 2017 average WI production of 679 BOEPD respectively, relating to theBrazil operations, which were sold inJune 2017 . (3) Sales volumes represent production NAR adjusted for inventory changes. In 2017,Brazil operations contributed 580 BOEPD.
32
--------------------------------------------------------------------------------
Consolidated Results of Operations
Year Ended December 31,
2019 % Change 2018 % Change 2017
(Thousands of U.S. Dollars)
Oil and natural gas sales $ 570,983 (7 ) $ 613,431 45 $ 421,734
Operating expenses 142,086 28 111,272 27 87,855
Workover expenses 41,118 19 34,437 56 22,014
Transportation expenses 20,400 (30 ) 28,993 15 25,107
Operating netback(1) 367,379 (16 ) 438,729 53 286,758
DD&A expenses 225,033 14 197,867 51 131,335
Asset impairment - - - (100 ) 1,514
G&A expenses before stock-based
compensation 33,300 6 31,369 5 29,775
G&A stock-based compensation
expense 1,430 (82 ) 8,114 (12 ) 9,239
Severance expenses 1,771 (25 ) 2,361 83 1,287
Equity tax - - - (100 ) 1,224
Foreign exchange loss 627 (94 ) 9,957 382 2,067
Financial instruments (gain)
loss (46,215 ) (476 ) 12,296 (23 ) 15,929
Interest expense 43,268 58 27,364 97 13,882
259,214 (10 ) 289,328 40 206,252
Other loss (12,886 ) 100 - (100 ) (44,385 )
Interest income 696 (67 ) 2,086 73 1,209
Income before income taxes 95,975 (37 ) 151,487 306 37,330
Current income tax expense 17,058 (61 ) 43,903 81 24,322
Deferred income tax expense 40,227 710 4,968 (89 ) 44,716
Total income tax expense 57,285 17 48,871 (29 ) 69,038
Net Income (loss) $ 38,690 (62 ) $ 102,616 424 $ (31,708 )
Sales Volumes (NAR)
Total sales volumes, BOEPD 29,140 1 28,717 8 26,689
Brent Price per bbl $ 64.16 (11 ) $ 71.69 31 $ 54.82
Consolidated Results of
Operations per BOE Sales Volumes
(NAR)
Oil and natural gas sales $ 53.68 (8 ) $ 58.53 35 $ 43.29
Operating expenses 13.36 26 10.62 18 9.02
Workover expenses 3.87 18 3.29 46 2.26
Transportation expenses 1.92 (31 ) 2.77 7 2.58
Operating netback(1) 34.53 (17 ) 41.85 42 29.43
33--------------------------------------------------------------------------------
DD&A expenses 21.16 12 18.88 40 13.48
Asset impairment - - - (100 ) 0.16
G&A expenses before stock-based compensation 3.13 5 2.99 (2 ) 3.06
G&A stock-based compensation expense 0.13 (83 ) 0.77 (19 ) 0.95
Severance expenses 0.17 (26 ) 0.23 77 0.13
Equity tax - - - (100 ) 0.13
Foreign exchange loss 0.06 (94 ) 0.95 352 0.21
Financial instruments (gain) loss (4.35) (472 ) 1.17 (29 ) 1.64
Interest expense 4.07 56 2.61 83 1.43
24.37 (12 ) 27.60 30 21.19
Other loss (1.21 ) 100 - (100 ) (4.56 )
Interest income 0.07 (65 ) 0.20 67 0.12
Income before income taxes 9.02 (38 ) 14.45 280 3.80
Current income tax expense 1.60 (62 ) 4.19 68 2.50
Deferred income tax expense 3.78 704 0.47 (90 ) 4.59
5.38 15 4.66 (34 ) 7.09
Net Income (loss) $ 3.64 (63 ) $ 9.79 398 $ (3.29 )
(1) Operating netback is a non-GAAP measure which does not have any standardized
meaning prescribed under GAAP. Refer to "Financial and Operating Highlights -
non-GAAP measures" for a definition and reconciliation of this measure.
Oil and Gas Production and Sales Volumes, BOEPD
Year Ended December 31,
Average Daily Volumes (BOEPD) 2019 2018 2017
Working Interest Production Before Royalties 34,817 36,209
32,105
Royalties (5,802 ) (7,156 ) (5,320 )
Production NAR(1) 29,015 29,053 26,785
Decrease (Increase) in Inventory 125 (336 ) (96 )
Sales (1) 29,140 28,717 26,689
Royalties, % of Working Interest Production Before Royalties 17 % 20 % 17 %
(1)
Oil and gas production NAR for the year ended
Royalties as a percentage of production for the year ended
Oil and gas production NAR for the year endedDecember 31, 2018 , increased by 8% to 29,053 BOEPD compared with 26,785 BOEPD in 2017. Production increased as a result of a successful drilling and workover campaign in the Acordionero Field. During 2018 we drilled 15 wells in the Acordionero Field.
34
--------------------------------------------------------------------------------
Operating Netbacks Consolidated Year Ended December 31, (Thousands of U.S. Dollars) 2019 2018 2017 Oil and Gas Sales$ 570,983 $ 613,431 $ 421,734 Transportation Expenses (20,400 ) (28,993 ) (25,107 ) 550,583 584,438 396,627 Operating Expenses (142,086 ) (111,272 ) (87,855 ) Workover Expenses (41,118 ) (34,437 ) (22,014 ) Operating Netback(1)$ 367,379 $ 438,729 $ 286,758 (U.S. Dollars per BOE Sales Volumes NAR) Brent$ 64.16 $ 71.69 $ 54.82 Quality and Transportation Discounts (10.48 ) (13.16 ) (11.53 ) Average Realized Price 53.68 58.53 43.29 Transportation Expenses (1.92 ) (2.77 ) (2.58 ) Average Realized Price Net of Transportation Expenses 51.76 55.76 40.71 Operating Expenses (13.36 ) (10.62 ) (9.02 ) Workover Expenses (3.87 ) (3.29 ) (2.26 ) Operating Netback(1)$ 34.53 $ 41.85 $ 29.43 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operating Highlights - non-GAAP measures" for a definition and reconciliation of this measure. 2017 figures include$6,271 of operating netback from operations inBrazil , which were sold inJune 2017 .
Oil and gas sales for the year ended
Oil and gas sales for the year endedDecember 31, 2018 , increased compared to$421.7 million in 2017, primarily as a result of increased sales volumes and higher average realized oil prices. The following table shows the effect of changes in realized price and sales volumes on our oil and gas sales for the three years endedDecember 31, 2019 : Year Ended December 31, 2019 2018 2017 Oil and natural gas sales for the comparative period$ 613,431 $ 421,734 $ 289,269 Realized sales price (decrease) increase effect (51,485 ) 159,653
100,304
Sales volume increase effect 9,037 32,044
32,161
Oil and natural gas sales for the current period$ 570,983 $ 613,431 $ 421,734 On a per BOE basis, average realized prices decreased by 8% to$53.68 for the year endedDecember 31, 2019 compared to$58.53 in 2018 primarily as a result of the decrease in benchmark oil prices. Average Brent oil prices for the year endedDecember 31, 2019 decreased by 11% compared to 2018. Brent oil price decreased by$7.53 per bbl but realized prices only decreased by$4.85 per bbl. On a per BOE basis, average realized price increased by 35% to$58.53 for the year endedDecember 31, 2018 compared to$43.29 in 2017. The increase in realized prices was consistent with higher benchmark oil prices. Average Brent oil price for the year endedDecember 31, 2018 increased by 31% compared with 2017. We have options to sell our oil through multiple pipelines and trucking routes. Each transportation route has varying effects on realized price and transportation expenses. The following table shows the percentage of oil volumes we sold inColombia using each transportation method for each of the three years endedDecember 31, 2019 : 35
--------------------------------------------------------------------------------
Year Ended December 31,
2019 2018 2017
Volume transported through pipelines 1 % 8 % 16 %
Volume sold at wellhead 51 % 40 % 52 %
Volume transported via truck to pipelines 48 % 52 % 32 %
100 % 100 % 100 %
Volumes transported through pipelines or via truck receive a higher realized
price, but incur higher transportation expenses. Volumes sold at the wellhead
have the opposite effect of lower realized price, offset by lower transportation
expense. We focus on maximizing operating netback per barrel when choosing a
transportation method.
Transportation expenses for the year ended December 31, 2019 , decreased by 30%
to $20.4 million , compared with $29.0 million in 2018. On a per BOE basis,
transportation expenses decreased 31% to $1.92 , from $2.77 in 2018. The decrease
in transportation expenses per BOE was due to higher volume sold at wellhead
where the transportation is netted against sales price and shorter trucking
routes to pipelines which lowered the transportation costs.
Transportation expenses for the year ended December 31, 2018 , increased 15% to
$29.0 million , compared with $25.1 million in 2017. On a per BOE basis,
transportation expenses increased 7% to $2.77 , from $2.58 in 2017. The increase
in transportation expenses per BOE was primarily due to a lower volume sold at
wellhead and higher volume sold from the Acordionero field, which is subject to
transportation costs.
The following table shows the variance in our average realized price net of
transportation expenses in
Year Ended December 31,
(U.S. Dollars per BOE Sales Volumes NAR) 2019 2018 2017
Average realized price net of transportation expenses for the comparative period$ 55.76 $ 40.71 $ 29.38 (Decrease) increase in benchmark prices (7.53 ) 16.87
10.49
Decrease (increase) in quality and transportation discounts 2.68 (1.63 ) (0.20 ) Decrease (increase) in transportation expense 0.85 (0.19 ) 1.04 Average realized price net of transportation expenses for the year$ 51.76 $ 55.76 $ 40.71 Operating expenses for the year endedDecember 31, 2019 , increased 28% to$142.1 million compared to$111.3 million in 2018. On a per BOE basis, operating expenses increased by$2.74 to$13.36 compared to$10.62 in prior year, primarily as a result of higher power generation and rental costs. During 2019, we fully commissioned the Acordionero expansion and gas-to-power facilities. These projects will allow expanded water injection and delivery of enhanced power reliability, which are expected to reduce operating costs and enhance ultimate recovery of oil and gas in the Acordionero field. With the commissioning of the permanent facilities and gas-to-power projects, we are expecting to reduce operating costs by terminating contracts related to rental facilities in the field and generating power through natural gas produced in the field instead of purchased diesel. Operating expenses for the year endedDecember 31, 2018 , increased 27% to$111.3 million , compared to$87.9 million in 2017. On a per BOE basis, operating expenses increased by$1.60 to$10.62 compared to$9.02 in 2017. The increase in operating expenses per BOE in 2018 was primarily as a result of higher power generation and equipment rental costs required to manage the capacity limitations in the Acordionero field as a result of rapid production growth. Workover expenses on a per BOE basis, increased by$0.58 to$3.87 for the year endedDecember 31, 2019 compared to 2018, due to a higher frequency of ESP failures during 2019 primarily because of power outages. With the gas-to-power facilities fully commissioned in 2019, we expect workover costs per BOE to decrease in 2020. Workover expenses on a per BOE basis, increased by$1.03 to$3.29 for the year endedDecember 31, 2018 compared to 2017 due to replacement of ESPs during 2018 resulting from unreliable power. 36
--------------------------------------------------------------------------------
DD&A Expenses
Year Ended December 31,
2019 2018 2017
DD&A Expenses, thousands of
21.16 18.88 13.48
(1) For the year-ended 2017, Corporate,
DD&A expenses for the year endedDecember 31, 2019 , increased by 14% from 2018 (12% on a per BOE basis), and increased by 51% (40% on a per BOE basis) in 2018 from 2017. On a per BOE basis, DD&A increases in 2019 and 2018 compared to prior years were due to higher costs in the depletable base partially offset by increased proved reserves. Asset Impairment Year Ended December 31, (Thousands of U.S. Dollars) 2019 2018 2017 Impairment of oil and gas properties(1) $ - $ -$ 1,514 $ - $ -$ 1,514
(1) For the year-ended 2017,
We follow the full cost method of accounting for our oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated "ceiling". The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12-month 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. For the years endedDecember 31, 2019 , 2018 and 2017, no ceiling test impairment was recorded in ourColombia cost center. In accordance with GAAP, we used an average Brent price of$64.20 per bbl for the purposes of theDecember 31, 2019 ceiling test calculation (December 31, 2018 - 72.08;December 31, 2017 - 54.19). G&A Expenses Year Ended December 31, (Thousands of U.S. Dollars) 2019 % change 2018 % change 2017 G&A Expenses Before Stock-Based Compensation$ 33,300 6$ 31,369 5$ 29,775 G&A Stock-Based Compensation 1,430 (82 ) 8,114 (12 ) 9,239 G&A Expenses, Including Stock-Based Compensation$ 34,730 (12 )$ 39,483
1
U.S. Dollars Per BOE Sales Volumes NAR G&A Expenses Before Stock-Based Compensation$ 3.13 5$ 2.99 (2 )$ 3.06 G&A Stock-Based Compensation 0.13 (83 ) 0.77 (19 ) 0.95 G&A Expenses, Including Stock-Based Compensation$ 3.26 (13 )$ 3.76 (6 )$ 4.01 G&A expenses, on a per BOE basis, after stock-based compensation decreased 13% to$3.26 in 2019 compared to prior year, mainly as a result of decrease in stock-based compensation commensurate with the decrease in stock price during 2019, partially offset by lower recoveries and a reduction of capitalized G&A during 2019. G&A expenses, on a per BOE basis, after stock-based compensation decreased 6% to$3.76 in 2018 compared to prior year, mainly as a result of production NAR growth and a decrease in stock-based compensation during the fourth quarter of 2018. 37
--------------------------------------------------------------------------------
G&A expenses, on a per BOE basis, before stock-based compensation increased 5% in 2019 compared to 2018 and decreased 2% in 2018 compared to 2017.
Severance Expenses
For the years ended
Equity Tax Expense
For the years endedDecember 31, 2019 , 2018 and 2017, the equity tax expense was nil, nil, and$1.2 million , respectively, and was calculated based on our Colombian legal entities' balance sheet atJanuary 1st of the year. The Equity Tax expense expired as ofJanuary 1, 2019 , and the modified version re-introduced in the 2018 Colombian Tax Reform is not applicable to our Colombian legal entities.
Foreign Exchange Gains and Losses
For the years endedDecember 31, 2019 , 2018 and 2017, we had foreign exchange losses of$0.6 million ,$10.0 million and$2.1 million , respectively. The main sources of the foreign exchange gains and losses are revaluation of taxes receivable and payable, investment in PetroTal shares and deferred tax liabilities. Under GAAP, deferred taxes are considered a monetary liability and require translation from local currency toU.S. dollar functional currency at each balance sheet date.
The following table presents the change in the Colombian peso against the
Year Ended
2019 2018 2017
Change in the Colombian peso against the
1% 9% 1%
Change in theU.S. dollar against the Canadian strengthened by weakened by strengthened by dollar 5% 9% 7%
Financial Instrument Gains and Losses
The following table presents the nature of our financial instruments gains and
losses for each of the three years ended
Year Ended December 31,
(Thousands of U.S. Dollars) 2019 2018 2017
Commodity price derivative loss
(49,884 ) (786 ) (111 )
$ (46,215 ) $ 12,296 $ 15,929 For the year ended
Other Loss
Other loss for the year endedDecember 31, 2019 , was related primarily to the loss on retirement of Convertible notes of$11.5 million . For the year endedDecember 31, 2017 , other loss was related to the loss on sale of ourBrazil business unit onJune 30, 2017 and ourPeru business unit onDecember 18, 2017 . 38
--------------------------------------------------------------------------------
Income Tax Expense and Recovery
Year Ended December 31 ,
(Thousands of
Current income tax expense
Effective tax rate 60 % 32 % 185 %
Current income tax expense decreased for the year ended
The deferred income tax expense for the year endedDecember 31, 2019 , of$40.2 million was primarily a result of excess tax depreciation compared to accounting depreciation inColombia . The deferred income tax expense for the year endedDecember 31, 2018 of$5.0 million was primarily a result of excess tax depreciation compared to accounting depreciation inColombia , which was partially offset by the impact of the release of the valuation allowance inColombia . In general, tax depreciation for capital expenditures investments incurred prior to 2017 is on straight-line over five years; and accounting depreciation is based on the unit of production method. The deferred income tax expense in 2017 was the result of tax depreciation being higher than accounting depreciation inColombia . Our effective tax rate was 60% for the year endedDecember 31, 2019 , compared with 32% in 2018. The increase in the effective tax rate was primarily due to an increase in the valuation allowance, mainly as a result of the recognition of previously unrecognized tax benefits inColombia during 2018; and other permanent differences. Our effective tax rate was 32% for the year endedDecember 31, 2018 , compared with 185% in 2017. The decrease in the effective tax rate was primarily due to a decrease in the valuation allowance, mainly as a result of the recognition of previously unrecognized tax benefits inColombia during 2018. This was partially offset by an increase in the impact of foreign taxes and other non-deductible expenses. The difference between our effective tax rate of 60% for the year endedDecember 31, 2019 , and the 33% Colombian statutory rate was primarily due to an increase in foreign currency translation, impact of foreign taxes, increase in valuation allowance and non-deductible third party royalties inColombia . The difference between our effective tax rate of 32% for the year endedDecember 31, 2018 , and the 37% Colombian statutory rate was primarily due to a decrease in the valuation allowance and other permanent differences. These are partially offset by an increase in foreign currency translation, the impact of foreign taxes and non-deductible third party royalties inColombia . 39
--------------------------------------------------------------------------------
Net Loss and Funds Flow From Operations (a Non-GAAP Measure)
Fourth quarter 2019 % change Fourth quarter 2019 % change Year ended % change
compared with third compared with fourth December 31,
quarter 2019 quarter 2018 2019 compared
with year
ended
December 31,
(Thousands of U.S. Dollars) 2018
Net (loss) income for the
comparative period $ (28,833 ) $ (10,840 ) $ 102,616
Increase (decrease) due to:
Sales volumes 463 (14,331 ) 9,037
Prices (5,020 ) 5,627 (51,485 )
Expenses:
Cash operating expenses,
excluding stock-based
compensation expense (2,364 ) (4,348 ) (30,999 )
Workover (114 ) (2,578 ) (6,681 )
Transportation (1,054 ) 3,736 8,593
Cash G&A and RSU
settlements, excluding
stock-based compensation
expense (873 ) 5,602 (1,571 )
Severance (549 ) (343 ) 590
Interest, net of
amortization of debt issuance
costs (447 ) (5,575 ) (15,711 )
Realized foreign exchange
loss (gain) 1,882 (327 ) (378 )
Settlement of financial
instruments (68 ) 6,764 30,658
Other loss (1,385 ) (1,385 ) (1,385 )
Current taxes (86 ) 4,544 26,845
Net lease payments 357 74 (163 )
Interest Income (94 ) 72 (1,390 )
Net change in funds flow from
operations(1)
from comparative period (9,352 ) (2,468 ) (34,040 )
Expenses:
Depletion, depreciation and accretion (10,791 ) (434 ) (27,166 ) Deferred tax (3 ) (3,389 ) (35,259 ) Amortization of debt issuance costs (13 ) 52 (193 ) Loss on convertible notes 11,109 (196 ) (11,501 ) Net Lease Payments (357 ) (74 ) 163 Stock-based compensation, net of RSU settlement (346 ) (12,516 ) 6,509 Financial instruments gain or loss, net of financial instruments settlements 55,678 42,017 27,853 Unrealized foreign exchange 9,912 14,852 9,708 Net change in net income or loss 55,837 37,844 (63,926 ) Net income for the current period$ 27,004 (194 )%$ 27,004 349 %$ 38,690 62 % (1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operating Highlights - non-GAAP measures" for a definition and reconciliation of this measure. 40
--------------------------------------------------------------------------------
2020 Work Program and Capital Expenditures
The table below shows the break-down of our 2020 capital program:
Number of Wells Number of Wells 2020 Capital Budget
(Gross) (Net) ($ million)
Colombia
Development 16-19 15-18 140-160
Exploration 1-2 1-2 25-35
Ecuador
Exploration 0-1 0-1 0-10
17-22 16-21 175-195(1)
(1) Assumes mid-point of budgeted amount for exploration
Based on the mid-point of the 2020 guidance, the capital budget is forecasted to be approximately 80% directed to development and 20% to exploration. Approximately 20% of the development activities included in the 2020 capital program are expected to be directed to facilities.
We expect our 2020 capital program to be fully funded by cash flows from operations.
Capital Program
Capital expenditures during the year ended
During the year ended
Number of wells
(Gross and Net)
Colombia
Development 25.0
Exploration 6.0
Service 5.0
Total 36.0
We spud six exploration, five service, and 25 development wells in 2019.
Approximately 80% of the development wells and all service wells were in the
Acordionero Field on the Midas Block. The six exploration wells were spud in the
PUT-1, PUT-7, El Porton , Llanos-10 and Santana Blocks .
We also commissioned facilities in the Acordionero Field and continued facilities work in the Moqueta Field on the Chaza Block.
Liquidity and Capital Resources
As at December 31,
(Thousands of U.S. Dollars) 2019 % Change 2018 % Change 2017
Cash and Cash Equivalents $ 8,301 (84 ) $ 51,040 314 $ 12,326
Current Restricted Cash and Cash
Equivalents $ 516 (59 ) $ 1,269 (89 ) $ 11,787
Revolving Credit Facility $ 118,000 100 $ - (100 ) $ 148,000
Senior Notes $ 600,000 100 $ 300,000 100 $ -
Convertible Notes $ - (100 ) $ 115,000 - $ 115,000
41--------------------------------------------------------------------------------
We believe that our capital resources, including cash on hand, cash generated from operations and available capacity on our credit facility, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for 2020, given current oil price trends and production levels. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested inU.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. OnMay 20, 2019 , we issued$300.0 million of 7.75% Senior Notes. The 7.75% Senior Notes are fully and unconditionally guaranteed by certain of our subsidiaries that guarantee our revolving credit facility. Net proceeds from the issue of the 7.75% Senior Notes were$289.3 million , after deducting the initial purchasers' discounts and commission and the offering expenses payable by us. The 7.75% Senior Notes bear interest at a rate of 7.75% per year, payable semi-annually in arrears onMay 23 andNovember 23 of each year, beginning onNovember 23, 2019 . The 7.75% Senior Notes will mature onMay 23, 2027 , unless earlier redeemed or repurchased. During the year, we purchased and canceled$114,999,000 aggregate principal amount of Convertible Notes, including$114,997,000 aggregate principal amount purchased and canceled pursuant to a previously announced offer to purchase for cash all outstanding Convertible Notes. OnFebruary 15, 2018 , through our indirect wholly-owned subsidiary,Gran Tierra Energy International Holdings Ltd. , we issued$300.0 million aggregate principal amount of 6.25% Senior Notes due 2025 (the "6.25% Senior Notes") in a private placement transaction. The 6.25% Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears onFebruary 15 andAugust 15 of each year, beginning onAugust 15, 2018 . The 6.25% Senior Notes will mature onFebruary 15, 2025 , unless earlier redeemed or repurchased. The net proceeds of the 6.25% Notes were used to repay the outstanding amount on the revolving credit facility, with the remainder for general corporate purposes. As atDecember 31, 2019 , we had a fully committed revolving credit facility with a syndicate of lenders with a borrowing base of$300.0 million with$182.0 million of undrawn capacity under the facility. We intentionally apply all excess cash to the facility and minimize cash on the balance to reduce borrowing costs. We can borrow under the facility by providing the lenders with two days notice. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. Under the terms of our credit facility we are required to maintain compliance with certain financial and operating covenants which include: the maintenance of a ratio of debt, including letters of credit, to net income plus interest, taxes, depreciation, depletion, amortization, exploration expenses and all non-cash charges minus all non-cash income (as defined in our credit agreement, "EBITDAX") not to exceed 4.0 to 1.0; the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. As atDecember 31, 2019 , we were in compliance with all financial and operating covenants in our credit agreement. Under the terms of the credit facility, we are limited in our ability to pay any dividends to our shareholders without bank approval.
Cash and Cash Equivalents Held Outside of
At
Derivative Positions
AtDecember 31, 2019 , we had outstanding commodity price derivative positions as follows: Purchased Sold Call Premium Put ($/bbl, ($/bbl, ($/bbl, Volume, Weighted Weighted Weighted
Period and type of instrument bopd Reference Average) Average) Average)
Collars:
A collar limits the range of possible positive and negative returns and provides us downside protection at a lower cost compared to a protective swap.
At
42
--------------------------------------------------------------------------------
U.S. Dollar
Equivalent of Floor
Amount Hedged Price Cap Price
(Thousands of (COP, (COP,
Period and type of Amount Hedged U.S. Weighted Weighted
instrument (Millions COP) Dollars)(1 ) Reference Average) Average)
Collars: January 1 , to
December 31, 2020 134,500 40,994 COP 3,305 3,423
Cash Flows
The following table presents our sources and uses of cash and cash equivalents
for the periods presented:
Year Ended December 31,
2019 2018 2017
Sources of cash and cash equivalents:
Net income (loss) $ 38,690 $ 102,616 $ (31,708 )
Adjustments to reconcile net loss to funds
flow from operations
DD&A expenses 225,033 197,867 131,335
Asset impairment - - 1,514
Deferred tax expense 40,227 4,968 44,716
Stock-based compensation expense 1,430 8,299 9,775
Amortization of debt issuance costs 3,376 3,183
2,415
Cash settlement of RSUs - (360 )
(564 )
Unrealized foreign exchange loss 1,803 11,511
837
Financial instruments (gain) loss (46,215 ) 12,296 15,929 Non-cash lease expenses 1,806 - - Lease payments (1,969 ) - - Cash settlement of financial instruments (3,273 ) (33,931 )
1,563
Loss on redemption of convertible notes 11,501 - - Loss on sale - - 44,385 Funds flow from operations(1) 272,409 306,449 220,197 Proceeds from issuance of Senior Notes, net of issuance costs 289,271 288,131
-
Proceeds from other debt, net of issuance costs 342,575 4,560
167,043
Changes in non-cash investing working capital - 17,704
19,680
Proceeds from exercise of stock options - 1,429
-
Net proceeds from sale of business units - -
32,968
904,255 618,273 439,888
Uses of cash and cash equivalents: Additions to property, plant and equipment - property acquisitions (77,772 ) (53,200 ) (34,410 ) Additions to property, plant and equipment (379,314 ) (347,093 ) (251,041 ) Repayment of debt (349,219 ) (153,000 ) (110,000 ) Cash paid for investments - - (11,000 ) Changes in non-cash operating working capital (93,874 ) (21,421 ) (29,217 ) Changes in non-cash investing working capital (7,851 ) -
-
Cash settlement of asset retirement obligation (870 ) (519 )
(1,336 )
Repurchase of shares of Common Stock (37,561 ) (12,742 ) (17,916 )
Foreign exchange loss on cash, cash
equivalents and restricted cash and cash
equivalents (1,027 ) (2,668 ) (1,557 )
(947,488 ) (590,643 ) (456,477 )
Net (decrease) increase in cash, cash
equivalents and restricted cash and cash
equivalents $ (43,233 ) $ 27,630
(1) Funds flow from operations is a non-GAAP measure which does not have any
standardized meaning prescribed under GAAP. Refer to "Financial and Operating
Highlights - non-GAAP measures" for a definition and reconciliation of this
measure.
43
--------------------------------------------------------------------------------
Off-Balance Sheet Arrangements
As at
Contractual Obligations
The following is a schedule by year of purchase obligations, future minimum
payments for firm agreements and leases that have initial or remaining
non-cancelable terms in excess of one year as of
Total 2020 2021-2022 2023-2024 2025 and
beyond
(Thousands of U.S.
Dollars)
Revolving credit
facility $ 118,000 $ - $ 118,000 $ - $ -
6.25% Senior Notes 300,000 - - - 300,000
7.75% Senior Notes 300,000 - - - 300,000
Total long-term debt 718,000 - 118,000 - 600,000
Interest payments(1) 289,090 46,070 91,572 84,000 67,448
Oil transportation
services 3,211 3,211 - - -
Drilling, completions
and seismic 21,409 7,602 13,669 39 99
Operating leases 5,679 2,708 2,971 - -
Finance leases 6,232 2,760 3,276 168 28
Total $ 1,043,621 $ 62,351 $ 229,488 $ 84,207 $ 667,575
(1) Interest payments were calculated by assuming that our revolving credit
facility outstanding balance at December 31, 2019 of $118 million will be
outstanding through the November 2022 maturity date and our 6.25% Senior Notes
and 7.75% Senior Notes will be held until their maturity dates of February 2025
and May 2027 , respectively. Actual results will differ from these estimates and
assumptions.
At December 31, 2019 , we had provided promissory notes totaling $120.6 million
to support letters of credit or surety bonds relating to work commitment
guarantees contained in exploration contracts and other capital or operating
requirements. These unsecured letters of credit do not utilize our revolving
credit facility capacity because they are backed by local Colombian banks and
Export Development Canada .
The above table does not reflect estimated amounts expected to be incurred in
the future associated with the abandonment of our oil and gas properties and
other long-term liabilities, as we cannot determine with accuracy the timing of
such payments. Information regarding our asset retirement obligation can be
found in Note 8 to the Consolidated Financial Statements, Asset Retirement
Obligation, in Item 8. "Financial Statements and Supplementary Data".
As is customary in the oil and gas industry, we may at times have commitments in
place to reserve or earn certain acreage positions or wells. If we do not meet
such commitments, the acreage positions or wells may be lost and associated
penalties may be payable.
Critical Accounting Policies and Estimates
The preparation of financial statements under GAAP requires management to make
estimates, judgments and assumptions that affect the reported amounts of assets
and liabilities as well as the revenues and expenses reported and disclosure of
contingent liabilities. Changes in these estimates related to judgments and
assumptions will occur as a result of changes in facts and circumstances or
discovery of new information, and, accordingly, actual results could differ from
amounts estimated.
On a regular basis we evaluate our estimates, judgments and assumptions. We also
discuss our critical accounting policies and estimates with the Audit Committee
of the Board of Directors.
Certain accounting estimates are considered to be critical if (a) the nature of
the estimates and assumptions is material due to the level of subjectivity and
judgment necessary to account for highly uncertain matters or the susceptibility
of such matters to changes; and (b) the impact of the estimates and assumptions
on financial condition or operating performance is material. The areas of
accounting and the associated critical estimates and assumptions made are
discussed below.
44--------------------------------------------------------------------------------
Full Cost Method of Accounting, Proved Reserves, DD&A and Impairment of
We follow the full cost method of accounting for our oil and natural gas
properties in accordance with SEC Regulation S-X Rule 4-10, as described in Note
2 to the Consolidated Financial Statements, Significant Accounting Policies, in
Item 8. "Financial Statements and Supplementary Data". Under the full cost
method of accounting, all costs incurred in the acquisition, exploration and
development of properties are capitalized, including internal costs directly
attributable to these activities. The sum of net capitalized costs, including
estimated asset retirement obligations ("ARO"), and estimated future development
costs to be incurred in developing proved reserves are depleted using the
unit-of-production method.
Companies that use the full cost method of accounting for oil and natural gas
exploration and development activities are required to perform a ceiling test
calculation. The ceiling test limits pooled costs to the aggregate of the
discounted estimated after-tax future net revenues from proved oil and gas
properties, plus the lower of cost or estimated fair value of unproved
properties less any associated tax effects.
If our net book value of oil and gas properties, less related deferred income
taxes, is in excess of the calculated ceiling, the excess must be written off as
an expense. Any such write-down will reduce earnings in the period of occurrence
and result in lower DD&A expenses in future periods. The ceiling limitation is
imposed separately for each country in which we have oil and gas properties. An
expense recorded in one period may not be reversed in a subsequent period even
though higher oil and gas prices may have increased the ceiling applicable to
the subsequent period.
Our estimates of proved oil and gas reserves are a major component of the
depletion and full cost ceiling calculations. Additionally, our proved reserves
represent the element of these calculations that require the most subjective
judgments. Estimates of reserves are forecasts based on engineering data,
projected future rates of production and the amount and timing of future
expenditures. The process of estimating oil and natural gas reserves requires
substantial judgment, resulting in imprecise determinations, particularly for
new discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data.
We believe our assumptions are reasonable based on the information available to
us at the time we prepare our estimates. However, these estimates may change
substantially as additional data from ongoing development activities and
production performance becomes available and as economic conditions impacting
oil and gas prices and costs change.
Management is responsible for estimating the quantities of proved oil and
natural gas reserves and for preparing related disclosures. Estimates and
related disclosures are prepared in accordance with
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that a 10% discount factor be used and future net revenues are calculated using prices that represent the average of the first day of each month price for the 12-month period. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs, but reflect adjustments for gravity, quality, local conditions, gathering and transportation fees and distance from market. Estimates of standardized measure of our future cash flows from proved reserves for ourDecember 31, 2019 , ceiling tests were based on wellhead prices per BOE as of the first day of each month within that twelve month period. Because the ceiling test calculation dictates the use of prices that are not representative of future prices and requires a 10% discount factor, the resulting value should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. Historical oil and gas prices for any particular 12-month period can be either higher or lower than our price forecast. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves. Our Reserves Committee oversees the annual review of our oil and gas reserves and related disclosures. The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reserves consultants to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reserves consultants, their independence.
45
--------------------------------------------------------------------------------
In the years endedDecember 31, 2019 and 2018, we had no ceiling test impairment losses. We used an average Brent price of$64.20 per bbl for the purposes of theDecember 31, 2019 ceiling test calculations (December 31, 2018 -$72.08 ;December 31, 2017 -$54.19 ). 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 prescribedU.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.Unproved Properties Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. Unproved properties, the costs of which are individually significant, are assessed individually by considering seismic data, plans or requirements to relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans and political, economic and market conditions. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, these properties are grouped for purposes of assessing impairment. During any period in which factors indicate an impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, seismic evaluations, the assignment of proved reserves, availability of capital and other factors. For countries where a reserve base has not yet been established, the impairment is charged to earnings.
Asset Retirement Obligations
We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future ARO requires us to make estimates and judgments with respect to activities that will occur many years into the future. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate. We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities. In arriving at amounts recorded, we make numerous assumptions and judgments with respect to the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, inflation factors, credit-adjusted risk-free discount rates and changes in legal, regulatory, environmental and political environments. Because costs typically extend many years into the future, estimating future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A.
It is difficult to determine the impact of a change in any one of our assumptions. As a result, we are unable to provide a reasonable sensitivity analysis of the impact a change in our assumptions would have on our financial results.
Equity Method Investment DuringDecember 2017 , we acquired an investment in common shares of PetroTal in connection with the sale of ourPeru business unit. AtDecember 31, 2019 , this investment represented approximately 37% of PetroTal's issued and outstanding common shares. We determined that we did not have a controlling financial interest in PetroTal, but could exert significant influence over PetroTal's operating and financial policies as a result of our ownership interest in PetroTal and the right to nominate two directors to PetroTal's board of directors. Accordingly, we accounted for our investment in the common shares of PetroTal as an equity method investment, but elected the fair value option for this investment.
The fair value of the current portion of the investment was estimated using quoted market prices in active markets. The long-term portion of the investment was estimated based on quoted market prices and valuation technique using observable and one or more unobservable inputs. Information regarding the valuation of the investment can be found in Note 13 to the Consolidated Financial
46
--------------------------------------------------------------------------------
Statements, Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk in Item 8. "Financial Statements and Supplementary Data", which information is incorporated by reference here.
Goodwill represents the excess of the aggregate of the consideration transferred over net identifiable assets acquired and liabilities assumed. The goodwill on our balance sheet relates entirely to ourColombia reporting unit. At each reporting date, we assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount and whether it is necessary to perform the goodwill impairment test. Changes in our future cash flows, operating results, growth rates, capital expenditures, cost of capital, discount rates, stock price or related market capitalization, could affect the results of our annual goodwill assessment and, accordingly, potentially lead to future goodwill impairment charges. The goodwill impairment test would require a comparison of the fair value of the reporting unit to its net book value. If the estimated fair value of the reporting unit were less than its net book value, including goodwill, we would recognize the goodwill impairment in an amount not exceeding the carrying amount of goodwill through a charge to expense. The most significant judgments involved in estimating the fair value of our reporting unit would relate to the valuation of our property and equipment. Unfavorable changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.
At
Revenue Recognition Our revenue relates to oil and natural gas sales inColombia . We recognize revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Payment terms are generally within three business days following delivery of an invoice to the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents our share and is recorded net of royalty payments to governments and other mineral interest owners. We evaluate our arrangement with third parties and partners to determine if we act as a principal or an agent. In making this evaluation, our management considers if we obtain control of the product delivered, which is indicated by us having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If we act in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by us from the transaction. Tariffs, tolls and fees charged to other entities for use of pipelines owned by us are evaluated by management to determine if these originate from contracts with customers or from incidental arrangements. In the comparative period, revenue from the production of oil and natural gas was recognized when the customer took title and assumed the risks and rewards of ownership, prices were fixed or determinable, the sale was evidenced by a contract and collection of the revenue was reasonably assured.
When determining if we acted as a principal or as an agent in transactions, management determines if we obtain control of the product. As part of this assessment, management considers detailed criteria for revenue recognition set out in ASC 606.
Income Taxes
We follow the liability method of accounting for income taxes whereby we
recognize deferred income tax assets and liabilities for the future tax
consequences attributable to differences between the financial statement
carrying amounts of assets and liabilities and their respective tax bases.
Deferred tax assets are also recognized for the future tax benefits attributable
to the expected utilization of existing tax net operating loss carryforwards and
other types of carryforwards. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in the years in
which those temporary differences and carryforwards are expected to be recovered
or settled. The effect on deferred tax assets and liabilities of a change in tax
rates is recognized in income in the period that includes the enactment date.
We carry on business in several countries and as a result, we are subject to
income taxes in numerous jurisdictions. The determination of our income tax
provision is inherently complex and we are required to interpret continually
changing regulations and make
47--------------------------------------------------------------------------------
certain judgments. While income tax filings are subject to audits and reassessments, we believe we have made adequate provision for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes. To assess the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Our effective tax rate is based on pre-tax income and the tax rates applicable to that income in the various jurisdictions in which we operate. An estimated effective tax rate for the year is applied to our quarterly operating results. In the event that there is a significant unusual or discrete item recognized, or expected to be recognized, in our quarterly operating results, the tax attributable to that item would be separately calculated and recorded at the same time as the unusual or discrete item. We consider the resolution of prior-year tax matters to be such items. Significant judgment is required in determining our effective tax rate and in evaluating our tax positions. We establish reserves when it is more likely than not that we will not realize the full tax benefit of the position. We adjust these reserves in light of changing facts and circumstances.
We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts.
Legal and Other Contingencies
A provision for legal and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management's judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. Management closely monitors known and potential legal and other contingencies and periodically determines when we should record losses for these items based on information available to us.
Stock-Based Compensation
Our stock-based compensation cost is measured based on the fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes simulation stock option-pricing model and/or observable share prices. These estimates depend on certain assumptions, including volatility, risk-free interest rate, the term of the awards, the forfeiture rate and performance factors, which, by their nature, are subject to measurement uncertainty. We use historical data to estimate the expected term used in the Black-Scholes option pricing model, option exercises and employee departure behavior. Expected volatilities used in the fair value estimate are based on the historical volatility of our shares. The risk-free rate for periods within the expected term of the stock options is based on theU.S. Treasury yield curve in effect at the time of grant.
Recently Adopted Accounting Pronouncements
We adopted Accounting Standard Codification ("ASC") 842 Leases with a date of
initial application on January 1, 2019 in accordance with the modified
retrospective transition approach using the practical expedients available for
land easements and short-term leases. We did not elect the "suite" of practical
expedients or use the hindsight expedient in our adoption.
At inception of a contract, we assess whether a contract is, or contains, a
lease. A contract is, or contains, a lease if the contract conveys the right to
control the use of an identified asset for a period of time in exchange for
consideration. At inception of a contract that contains a lease component, we
allocate the consideration in the contract to each lease and non-lease component
on the basis of their relative stand-alone prices. We recognize a right-of-use
asset and a lease liability at the lease commencement date. The right-of-use
asset is initially measured at cost, and subsequently at cost less any
accumulated depreciation and impairment losses, and adjusted for certain
remeasurements of the lease liability.
The lease liability is initially measured at the present value of the lease
payments that are not paid at the commencement date, discounted using the
interest rate implicit in the lease or, if that rate cannot be readily
determined, our incremental borrowing rate. Generally, we use our incremental
borrowing rate as the discount rate. The lease liability is subsequently
increased by the interest cost on the lease liability and decreased by lease
payments made. It is remeasured when there is a change in future lease payments
arising from a change in an index or rate, a change in the estimate of the
amount expected to be payable under a residual value guarantee, or as
appropriate, changes in the assessment of whether a purchase or extension option
is reasonably certain to be exercised or a termination option is reasonably
certain not to be exercised.
48--------------------------------------------------------------------------------
We have applied judgment to determine the lease term for contracts which include renewal or termination options. The assessment of whether we are reasonably certain to exercise such options impacts the lease term, which significantly affects the amount of lease liabilities and right-of-use assets recognized.
All leases identified as part of the transition relate to office leases.
The transition resulted in the recognition of a right-of-use asset presented in other capital assets of$3.8 million atJanuary 1, 2019 , the recognition of lease liabilities of$4.2 million and a$0.4 million impact on retained earnings. When measuring the lease liabilities, our incremental borrowing rate was used. AtJanuary 1, 2019 the rates applied ranged between 5.6% and 9.1%.
New Accounting Pronouncements
InJune 2016 , the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses". This ASU replaces the current incurred loss impairment methodology with a methodology that reflects expected credit losses and requires a broader range of reasonable and supportable information to support credit loss estimates. InDecember 2019 , the FASB issued ASU 2019-10, "Financial Instruments - Credit Losses, Derivatives and Hedging and Leases", which is codification improvement of ASU 2016-13. The ASU will be effective for fiscal years, and interim periods within those years, beginning afterDecember 15, 2019 . We have adopted this ASU onJanuary 1, 2020 and applied a current expected credit loss model that has resulted in no impact on our consolidated position, results of operation or cash flows.
© Edgar Online, source
