|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Operating expenses
|
11.38
|
|
|
10.82
|
|
12.97
|
|
(17
|
)
|
|
10.97
|
|
9.86
|
|
11
|
|
Transportation expenses
|
2.71
|
|
|
2.39
|
|
2.92
|
|
(18
|
)
|
|
2.72
|
|
3.84
|
|
(29
|
)
|
Operating netback
(1)
|
26.10
|
|
|
27.88
|
|
18.79
|
|
48
|
|
|
27.51
|
|
17.52
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expenses
|
13.23
|
|
|
13.66
|
|
18.08
|
|
(24
|
)
|
|
12.97
|
|
16.51
|
|
(21
|
)
|
Asset impairment
|
0.07
|
|
|
0.31
|
|
161.88
|
|
(100
|
)
|
|
0.17
|
|
74.20
|
|
(100
|
)
|
G&A expenses before stock-based compensation
|
3.18
|
|
|
2.76
|
|
2.42
|
|
14
|
|
|
3.10
|
|
2.60
|
|
19
|
|
G&A stock-based compensation expense
|
0.80
|
|
|
0.67
|
|
0.41
|
|
63
|
|
|
0.66
|
|
0.66
|
|
—
|
|
Severance expenses
|
—
|
|
|
0.46
|
|
—
|
|
—
|
|
|
0.16
|
|
0.21
|
|
(24
|
)
|
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
|
)
|
Interest expense
|
1.39
|
|
|
1.58
|
|
2.59
|
|
(39
|
)
|
|
1.46
|
|
1.24
|
|
18
|
|
|
19.70
|
|
19.60
|
189.24
|
(90
|
)
|
|
18.07
|
97.52
|
(81
|
)
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
2.71
|
|
|
8.40
|
|
(170.08
|
)
|
105
|
|
|
8.30
|
|
(77.85
|
)
|
111
|
|
Current income tax expense
|
0.74
|
|
|
1.72
|
|
1.96
|
|
(12
|
)
|
|
1.89
|
|
1.84
|
|
3
|
|
Deferred income tax expense (recovery)
|
4.82
|
|
|
5.45
|
|
(55.88
|
)
|
110
|
|
|
5.13
|
|
(26.25
|
)
|
120
|
|
|
5.56
|
|
|
7.17
|
|
(53.92
|
)
|
113
|
|
|
7.02
|
|
(24.41
|
)
|
129
|
|
Net income (loss)
|
$
|
(2.85
|
)
|
|
$
|
1.23
|
|
$
|
(116.16
|
)
|
101
|
|
|
$
|
1.28
|
|
$
|
(53.44
|
)
|
102
|
|
(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.
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, BOEPD
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 NAR
for the three and
nine months ended September 30, 2017
,
increase
d by
25%
to
27,515
BOEPD and
19%
to
26,253
BOEPD, respectively, compared with
21,980
BOEPD and
22,154
BOEPD respectively, in the comparable 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
increase
d primarily due to the PetroLatina acquisition and a successful drilling campaign in the Acordionero Field in Colombia. The acquisition 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, 2017
Royalties as a percentage of production for the three and
nine months ended September 30, 2017
,
increase
d compared with the comparable period in the prior year commensurate with the
increase
in oil prices.
Despite the sale of our Brazil assets effective June 30, 2017, oil and gas production NAR for the
three months ended September 30, 2017
,
increase
d
4%
compared with the prior quarter as a result of a successful drilling and workover campaign in the Acordionero Field in Colombia, the successful Vonu-1 exploration well and a workover campaign in Cumplidor. Colombian NAR production
increased
9%
compared with the prior quarter.
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 volumes
increased
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
,
increase
d by
4%
to
27,447
BOEPD compared with
26,283
BOEPD in the prior quarter. Sales volumes
increase
d due to
higher
working interest production (
1,133
BOEPD) and lower inventory changes (
72
BOEPD) more than offset
higher
royalty volumes (
41
BOEPD).
Operating Netbacks
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 non-GAAP measures disclosure above regarding this measure.
Oil and gas sales
for the three and
nine months ended September 30, 2017
,
increase
d by
51%
to
$103.8 million
and by
49%
to
$294.6 million
, respectively, from
$68.5 million
and
$197.7 million
, respectively, in the comparable periods in
2016
due to
increase
d volumes and realized oil prices.
The following table shows the effect of changes in realized prices and sales volumes on our oil and gas sales for the three and
nine months ended September 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Average realized prices for the three and
nine months ended September 30, 2017
,
increase
d by
18%
and
32%
, respectively, commensurate with the
increase
in benchmark oil prices and lower transportation and quality discounts. Average Brent oil prices for the three and
nine months ended September 30, 2017
,
increase
d by
11%
and
25%
respectively.
Oil and gas sales for the
three months ended September 30, 2017
,
increase
d by
8%
to
$103.8 million
from
$96.1 million
compared with the prior quarter due to
higher
sales volumes and
increase
d realized oil prices. Average realized prices
increase
d 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
,
increase
d by
2%
to
$52.18
per bbl, compared with
$50.92
per bbl in the prior quarter.
We have options to sell our oil though multiple pipelines and trucking routes. Each transportation route has varying effects on realized prices and transportation expenses. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for the three and
nine months ended September 30, 2017
and
2016
and the prior quarter:
|
|
|
|
|
|
|
|
|
|
|
|
|
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 wellhead 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.
Transportation expenses
for the
three months ended September 30, 2017
,
increase
d by
5%
to
$6.0 million
compared with the corresponding period in
2016
. On a per BOE basis, transportation expenses
decrease
d 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 was due to the use of transportation routes which had lower costs per BOE than the routes used in 2016.
Transportation expenses for the
nine months ended September 30, 2017
,
decrease
d by
20%
to
$19.5 million
compared with the corresponding period in
2016
. On a per BOE basis, transportation expenses
decrease
d by
29%
to
$2.72
per BOE from
$3.84
per BOE in the corresponding period in
2016
. The
decrease
in transportation expenses per BOE was due to a higher percentage of volumes sold at the wellhead, as noted in the table above, and the use of transportation routes which had lower costs per BOE than the routes used in 2016.
Transportation expenses for the
three months ended September 30, 2017
,
decrease
d
7%
to
$6.0 million
compared with
$6.5 million
in the prior quarter. On a per BOE basis, transportation expenses
decrease
d by
12%
to
$2.39
from
$2.71
in the prior quarter. The
decrease
was primarily due to the use of transportation routes which had lower costs per BOE.
The following table shows the variance in our
average realized prices net of transportation expenses
in Colombia 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
,
increase
d 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
decrease
d by
17%
to
$10.82
per BOE from
$12.97
per BOE, in the corresponding period in
2016
primarily as a result of
decrease
d 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
increase
d by
$0.82
per BOE as discussed below.
In Colombia, operating costs for the
three months ended September 30, 2017
,
decrease
d by
$2.28
per BOE compared with the corresponding period in
2016
, primarily as a result of
decrease
d workover expenses of
$3.16
per BOE. Excluding workover expenses, operating expenses in Colombia
increase
d 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 million
and
$2.5 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, and we have had 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
,
increase
d by
26%
to
$78.5 million
, compared with the corresponding period in
2016
. The
increase
was due to
higher
sales volumes and
increase
d operating costs per BOE. On a per BOE basis, operating expenses
increase
d by
11%
to
$10.97
per BOE from
$9.86
per BOE, in the corresponding period in
2016
. Workover expenses
decrease
d by
$0.21
per BOE compared with the corresponding period in the prior year. Excluding workover expenses, operating costs
increase
d 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
,
increase
d by
$1.09
per BOE compared with the corresponding period in
2016
. Workover expenses
decrease
d by
$0.23
per BOE. Excluding workover expenses, operating expenses in Colombia
increase
d by
$1.32
per BOE primarily as a result of increased costs and production disruptions in 2017, as described above.
Operating expenses were comparable to the prior quarter at
$27.3 million
in the
three months ended September 30, 2017
. On a per BOE basis, operating expenses
decrease
d by
$0.56
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.
DD&A Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
,
decrease
d 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) in the comparable periods in
2016
. On a per BOE basis, the decrease was due to lower costs in the depletable base and increased proved reserves.
On a per BOE basis, DD&A expenses
increase
d by
3%
to
$13.66
per BOE for the
three months ended September 30, 2017
, from
$13.23
per BOE in the prior quarter due to higher costs in the depletable base from capital expenditures during the quarter ended September 30, 2017.
Asset Impairment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 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.
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
, G&A expenses increased by
46%
and
35%
, respectively, from the corresponding periods in 2016. The increase was commensurate with our growth. Since June 30, 2016, we have completed two acquisitions, drilled
25
wells, and grown production NAR
25%
from
21,980
BOEPD in the
third
quarter of 2016 to
27,515
BOEPD in 2017.
After stock-based compensation, G&A expenses for the three and
nine months ended September 30, 2017
,
increase
d by
55%
to
$8.7 million
(
$3.43
per BOE) and by
30%
to
$26.9 million
(
$3.76
per BOE), respectively, from
$5.6 million
(
$2.83
per BOE) and
$20.6 million
(
$3.26
per BOE), respectively, in the corresponding periods in
2016
. The
increase
was mainly due to the increased head count.
G&A expenses for the
three months ended September 30, 2017
,
decrease
d by
9%
to
$8.7 million
(
$3.43
per BOE) compared with
$9.5 million
(
$3.98
per BOE) 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
, we had foreign exchange
gain
s of
$1.3 million
and
loss
es of
$0.8 million
, respectively, compared with foreign exchange
gain
s of
$0.5 million
and
loss
es of
$1.1 million
, respectively, in the corresponding periods in
2016
. Under U.S. GAAP, deferred taxes are considered a monetary liability and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation was the main source of the foreign exchange gains and losses. The following table presents the change in the U.S. dollar against the Colombian peso for the three and
nine months ended September 30, 2017
, and
2016
:
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2017
|
2016
|
|
2017
|
2016
|
Change in the U.S. dollar against the Colombian peso
|
weakened by
|
weakened by
|
|
weakened by
|
weakened by
|
3%
|
1%
|
|
2%
|
9%
|
Financial Instrument Gains and Losses
The following table presents the nature of our financial instruments gains and losses for the three and
nine months ended September 30, 2017
, and
2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Income Tax Expense and Recovery
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 the
three months ended September 30, 2017
, compared with the corresponding period in
2016
primarily as a result of higher taxable income in Colombia. The deferred income tax expense of
$13.8 million
for the
three 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
$110.5 million
included
$119.3 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.
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
, the difference between the effective tax rate of
85%
and the 35% U.S. statutory rate was primarily due to the effect of foreign taxes, valuation allowances, non-deductible third party royalty in Colombia, stock-based compensation and other local taxes. These items were partially offset by foreign currency translation adjustments and other permanent differences.
For the
nine months ended September 30, 2016
, the difference between the effective tax rate of
31%
and the 35% U.S. statutory rate was primarily due to an increase to the valuation allowance, which was largely attributable to impairment losses in Brazil and Colombia, as well as non-deductible local taxes, stock based compensation and the non-deductible third-party royalty in Colombia. These items were partially offset by the impact of foreign taxes, foreign currency translation adjustments and other permanent differences. Other permanent differences mainly related to a non-taxable gain arising on the acquisition of Petroamerica, partially offset by prior periods' true-up adjustments, uncertain tax position adjustments and other expenses deductible for tax.
Net Income and Funds Flow from Operations (a Non-GAAP Measure)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 non-GAAP measures disclosure above regarding 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
, were
$71.7 million
:
|
|
|
|
|
(Thousands of U.S. Dollars)
|
|
Colombia
|
$
|
70,606
|
|
Peru
|
998
|
|
Corporate
|
90
|
|
|
$
|
71,694
|
|
During the nine months ended September 30, 2017, we drilled 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
|
|
The significant elements of our
third
quarter
2017
capital program 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 production 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.
|
|
|
•
|
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, 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
|
|
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
2017
, 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 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.
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.
I
n 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, we 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
|
|
At
September 30, 2017
, we had the following outstanding foreign currency derivative positions:
|
|
|
|
|
|
|
|
|
|
|
Period and type of instrument
|
Amount Hedged
(Millions COP)
|
U.S. Dollar Equivalent of Amount Hedged
(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, 2017
foreign exchange rate.
Subsequent to September 30, 2017, the we 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
|
|
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
|
)
|
Cash
provided by
operating activities in the
nine months ended September 30, 2017
, was primarily affected by
higher
funds flow from operations (see 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.
One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices, the impact of which we partially mitigate by entering into commodity derivatives. Sales volume changes and costs related to operations and debt service also impact cash flow. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes, the impact of which we partially mitigate by entering into foreign currency derivatives.
Off-Balance Sheet Arrangements
As at
September 30, 2017
, we had no off-balance sheet arrangements.
Contractual Obligations
During the
nine months ended September 30, 2017
, we borrowed a net amount of
$30.3 million
on our revolving credit facility. Additionally, at June 30, 2017, we sold our Brazil business unit and its related obligations. Except as noted above, as at
September 30, 2017
, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as at
December 31, 2016
.
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates are disclosed in Item 7 of our
2016
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:
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.