Consolidated Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2016
|
|
2016
|
|
2015
|
|
% Change
|
|
2016
|
|
2015
|
|
% Change
|
(Thousands of U.S. Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
57,403
|
|
|
$
|
71,713
|
|
|
$
|
69,350
|
|
|
3
|
|
|
$
|
129,116
|
|
|
$
|
145,581
|
|
|
(11
|
)
|
Operating expenses
|
|
19,067
|
|
|
17,748
|
|
|
17,758
|
|
|
—
|
|
|
36,815
|
|
|
40,419
|
|
|
(9
|
)
|
Transportation expenses
|
|
12,328
|
|
|
6,217
|
|
|
6,375
|
|
|
(2
|
)
|
|
18,545
|
|
|
15,148
|
|
|
22
|
|
Operating netback
(1)
|
|
26,008
|
|
|
47,748
|
|
|
45,217
|
|
|
6
|
|
|
73,756
|
|
|
90,014
|
|
|
(18
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expenses
|
|
36,912
|
|
|
31,884
|
|
|
39,188
|
|
|
(19
|
)
|
|
68,796
|
|
|
88,328
|
|
|
(22
|
)
|
Asset impairment
|
|
56,898
|
|
|
92,843
|
|
|
30,285
|
|
|
207
|
|
|
149,741
|
|
|
67,299
|
|
|
123
|
|
G&A expenses
|
|
8,286
|
|
|
7,975
|
|
|
10,298
|
|
|
(23
|
)
|
|
16,261
|
|
|
17,592
|
|
|
(8
|
)
|
Severance expenses
|
|
1,018
|
|
|
281
|
|
|
1,988
|
|
|
(86
|
)
|
|
1,299
|
|
|
6,366
|
|
|
(80
|
)
|
Equity tax
|
|
3,051
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,051
|
|
|
3,769
|
|
|
(19
|
)
|
Foreign exchange loss (gain)
|
|
785
|
|
|
781
|
|
|
2,969
|
|
|
(74
|
)
|
|
1,566
|
|
|
(8,569
|
)
|
|
118
|
|
Financial instruments loss (gain)
|
|
845
|
|
|
(1,072
|
)
|
|
(1,366
|
)
|
|
(22
|
)
|
|
(227
|
)
|
|
(1,408
|
)
|
|
84
|
|
|
|
107,795
|
|
|
132,692
|
|
|
83,362
|
|
|
59
|
|
|
240,487
|
|
|
173,377
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on acquisition
|
|
11,712
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,712
|
|
|
—
|
|
|
—
|
|
Interest expense
|
|
(519
|
)
|
|
(2,201
|
)
|
|
—
|
|
|
—
|
|
|
(2,720
|
)
|
|
—
|
|
|
—
|
|
Interest income
|
|
449
|
|
|
749
|
|
|
382
|
|
|
96
|
|
|
1,198
|
|
|
803
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
(70,145
|
)
|
|
(86,396
|
)
|
|
(37,763
|
)
|
|
129
|
|
|
(156,541
|
)
|
|
(82,560
|
)
|
|
90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income tax expense
|
|
(2,023
|
)
|
|
(5,778
|
)
|
|
(5,684
|
)
|
|
2
|
|
|
(7,801
|
)
|
|
(8,109
|
)
|
|
(4
|
)
|
Deferred income tax recovery
|
|
27,136
|
|
|
28,615
|
|
|
4,883
|
|
|
486
|
|
|
55,751
|
|
|
7,239
|
|
|
670
|
|
|
|
25,113
|
|
|
22,837
|
|
|
(801
|
)
|
|
—
|
|
|
47,950
|
|
|
(870
|
)
|
|
—
|
|
Net loss
|
|
$
|
(45,032
|
)
|
|
$
|
(63,559
|
)
|
|
$
|
(38,564
|
)
|
|
65
|
|
|
$
|
(108,591
|
)
|
|
$
|
(83,430
|
)
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Volumes
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and NGL's, bbl
|
|
2,292,116
|
|
|
2,020,722
|
|
|
1,349,127
|
|
|
50
|
|
|
4,312,836
|
|
|
3,084,025
|
|
|
40
|
|
Natural gas, Mcf
|
|
132,265
|
|
|
115,968
|
|
|
78,578
|
|
|
48
|
|
|
248,233
|
|
|
144,605
|
|
|
72
|
|
Total sales volumes, BOE
|
|
2,314,160
|
|
2,040,050
|
|
1,362,223
|
|
50
|
|
|
4,354,208
|
|
3,108,126
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales volumes, BOEPD
|
|
25,430
|
|
|
22,418
|
|
|
14,970
|
|
|
50
|
|
|
23,924
|
|
|
17,172
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and NGL's per bbl
|
|
$
|
24.88
|
|
|
$
|
35.31
|
|
|
$
|
51.18
|
|
|
(31
|
)
|
|
$
|
29.77
|
|
|
$
|
47.03
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas per Mcf
|
|
$
|
2.83
|
|
|
$
|
3.06
|
|
|
$
|
3.78
|
|
|
(19
|
)
|
|
$
|
2.94
|
|
|
$
|
3.82
|
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brent Price per bbl
|
|
$
|
33.70
|
|
|
$
|
45.52
|
|
|
$
|
61.70
|
|
|
(26
|
)
|
|
$
|
39.61
|
|
|
$
|
57.81
|
|
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Results of Operations per BOE sales volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
24.81
|
|
|
$
|
35.15
|
|
|
$
|
50.91
|
|
|
(31
|
)
|
|
$
|
29.65
|
|
|
$
|
46.84
|
|
|
(37
|
)
|
Operating expenses
|
|
8.24
|
|
|
8.70
|
|
|
13.04
|
|
|
(33
|
)
|
|
8.46
|
|
|
13.00
|
|
|
(35
|
)
|
Transportation expenses
|
|
5.33
|
|
|
3.05
|
|
|
4.68
|
|
|
(35
|
)
|
|
4.26
|
|
|
4.88
|
|
|
(13
|
)
|
Operating netback
(1)
|
|
11.24
|
|
|
23.40
|
|
|
33.19
|
|
|
(29
|
)
|
|
16.93
|
|
|
28.96
|
|
|
(42
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expenses
|
|
15.95
|
|
|
15.63
|
|
|
28.77
|
|
|
(46
|
)
|
|
15.80
|
|
|
28.42
|
|
|
(44
|
)
|
Asset impairment
|
|
24.59
|
|
|
45.51
|
|
|
22.23
|
|
|
105
|
|
|
34.39
|
|
|
21.65
|
|
|
59
|
|
G&A expenses
|
|
3.58
|
|
|
3.91
|
|
|
7.56
|
|
|
(48
|
)
|
|
3.73
|
|
|
5.66
|
|
|
(34
|
)
|
Severance expenses
|
|
0.44
|
|
|
0.14
|
|
|
1.46
|
|
|
(90
|
)
|
|
0.30
|
|
|
2.05
|
|
|
(85
|
)
|
Equity tax
|
|
1.32
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.70
|
|
|
1.21
|
|
|
(42
|
)
|
Foreign exchange loss (gain)
|
|
0.34
|
|
|
0.38
|
|
|
2.18
|
|
|
83
|
|
|
0.36
|
|
|
(2.76
|
)
|
|
113
|
|
Financial instruments loss (gain)
|
|
0.37
|
|
|
(0.53
|
)
|
|
(1.00
|
)
|
|
(47
|
)
|
|
(0.05
|
)
|
|
(0.45
|
)
|
|
89
|
|
|
|
46.59
|
|
65.04
|
|
61.20
|
|
6
|
|
|
55.23
|
|
55.78
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on acquisition
|
|
5.06
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.69
|
|
|
—
|
|
|
—
|
|
Interest expense
|
|
(0.22
|
)
|
|
(1.08
|
)
|
|
—
|
|
|
—
|
|
|
(0.62
|
)
|
|
—
|
|
|
—
|
|
Interest income
|
|
0.19
|
|
|
0.37
|
|
|
0.28
|
|
|
32
|
|
|
0.28
|
|
|
0.26
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
(30.32
|
)
|
|
(42.35
|
)
|
|
(27.73
|
)
|
|
53
|
|
|
(35.95
|
)
|
|
(26.56
|
)
|
|
35
|
|
Current income tax expense
|
|
(0.87
|
)
|
|
(2.83
|
)
|
|
(4.17
|
)
|
|
(32
|
)
|
|
(1.79
|
)
|
|
(2.61
|
)
|
|
(31
|
)
|
Deferred income tax recovery
|
|
11.73
|
|
|
14.03
|
|
|
3.58
|
|
|
292
|
|
|
12.80
|
|
|
2.33
|
|
|
449
|
|
|
|
10.86
|
|
|
11.20
|
|
|
(0.59
|
)
|
|
—
|
|
|
11.01
|
|
|
(0.28
|
)
|
|
—
|
|
Net loss
|
|
$
|
(19.46
|
)
|
|
$
|
(31.15
|
)
|
|
$
|
(28.32
|
)
|
|
10
|
|
|
$
|
(24.94
|
)
|
|
$
|
(26.84
|
)
|
|
(7
|
)
|
(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.
(2)
Sales volumes represent production NAR adjusted for inventory changes and losses.
Oil and gas production and sales volumes, BOEPD
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2016
|
|
Three Months Ended June 30, 2015
|
Average Daily Volumes (BOEPD)
|
Colombia
|
Brazil
|
Total
|
|
Colombia
|
Brazil
|
Total
|
Working Interest Production Before Royalties
|
24,818
|
|
926
|
|
25,744
|
|
|
22,601
|
|
493
|
|
23,094
|
|
Royalties
|
(3,921
|
)
|
(128
|
)
|
(4,049
|
)
|
|
(4,531
|
)
|
(69
|
)
|
(4,600
|
)
|
Production NAR
|
20,897
|
|
798
|
|
21,695
|
|
|
18,070
|
|
424
|
|
18,494
|
|
Decrease (Increase) in Inventory
|
713
|
|
10
|
|
723
|
|
|
(3,503
|
)
|
(21
|
)
|
(3,524
|
)
|
Sales
|
21,610
|
|
808
|
|
22,418
|
|
|
14,567
|
|
403
|
|
14,970
|
|
|
|
|
|
|
|
|
|
Royalties, % of Working Interest Production Before Royalties
|
16
|
%
|
14
|
%
|
16
|
%
|
|
20
|
%
|
14
|
%
|
20
|
%
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
Six Months Ended June 30, 2015
|
Average Daily Volumes (BOEPD)
|
Colombia
|
Brazil
|
Total
|
|
Colombia
|
Brazil
|
Total
|
Working Interest Production Before Royalties
|
24,852
|
|
825
|
|
25,677
|
|
|
22,947
|
|
605
|
|
23,552
|
|
Royalties
|
(3,298
|
)
|
(137
|
)
|
(3,435
|
)
|
|
(4,157
|
)
|
(83
|
)
|
(4,240
|
)
|
Production NAR
|
21,554
|
|
688
|
|
22,242
|
|
|
18,790
|
|
522
|
|
19,312
|
|
Decrease (Increase) in Inventory
|
1,680
|
|
2
|
|
1,682
|
|
|
(2,145
|
)
|
5
|
|
(2,140
|
)
|
Sales
|
23,234
|
|
690
|
|
23,924
|
|
|
16,645
|
|
527
|
|
17,172
|
|
|
|
|
|
|
|
|
|
Royalties, % of Working Interest Production Before Royalties
|
13
|
%
|
17
|
%
|
13
|
%
|
|
18
|
%
|
14
|
%
|
18
|
%
|
Oil and gas production NAR
for the three and
six months ended June 30, 2016
,
increased
by
17%
to
21,695
BOEPD and
increase
d by
15%
to
22,242
BOEPD, respectively, compared with
18,494
and
19,312
BOEPD, respectively, in the corresponding periods in
2015
. In the three and
six months ended June 30, 2016
, production increased primarily due to the acquisition of Petroamerica and the drilling program in the Costayaco and Moqueta Fields in Colombia. Royalties as a percentage of production decreased from the prior year commensurate with the decrease in oil prices. During the six months ended June 30, 2016, due to the low price environment we elected to defer a number of workovers in Costayaco and Moqueta until the second half of 2016. In the corresponding periods in Brazil in 2015, our operations in the Tiê Field were temporarily suspended by the Agência Nacional de Petróleo Gás Natural e Biocombustíveis ("ANP") from March 11, 2015, to May 15, 2015.
Oil and gas production NAR for the
three months ended June 30, 2016
,
decrease
d by
5%
compared with the prior quarter. As noted above, we deferred our workover program until the second half of 2016. In the first quarter of 2016, our production in Brazil was limited by a temporary capacity reduction at a third party's shipping facility due to an integrity issue with one of their oil receiving tanks. The third party operator completed repairs on the facility and the tank was fully operational as of March 21, 2016. Receiving capacity for the field's crude oil is now restored to 1,100 bopd.
Oil and gas sales volumes
for the three and
six months ended June 30, 2016
,
increased
by
50%
to
22,418
BOEPD, and
increased
by
39%
to
23,924
BOEPD, respectively, compared with
14,970
BOEPD and
17,172
BOEPD, respectively, in the corresponding periods in
2015
. Sales volumes increased due to
higher
working interest production (
2,650
and
2,125
BOEPD respectively),
lower
royalty volumes (
551
and
805
BOEPD respectively) and
decrease
d inventory (
4,247
and
3,822
BOEPD respectively). During the
three months ended June 30, 2016
, oil inventory
decrease
s accounted for
0.1
MMbbl or
723
bopd of
increased
sales volumes compared with oil inventory
increase
s which accounted for
0.3
MMbbl or
3,524
bopd of
reduced
sales volumes in the corresponding period in
2015
. During the
six months ended June 30, 2016
, oil inventory
decrease
s accounted for
0.3
MMbbl or
1,682
bopd of
increased
sales volumes compared with oil inventory
increase
s which accounted for
0.4
MMbbl or
2,140
bopd of
reduced
sales volumes in the corresponding period in
2015
.
Oil and gas sales for the
three months ended June 30, 2016
,
decrease
d by
12%
to
22,418
BOEPD compared with
25,430
BOEPD in the prior quarter. Sales volumes
decrease
d due to the effect of inventory changes (
1,919
BOEPD) and
higher
royalty volumes (
1,227
BOEPD), partially offset by
higher
working interest production (
134
BOEPD).
Operating netbacks
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2016
|
|
Three Months Ended June 30, 2015
|
(Thousands of U.S. Dollars)
|
Colombia
|
Brazil
|
Total
|
|
Colombia
|
Brazil
|
Total
|
Oil and Gas Sales
|
$
|
69,271
|
|
$
|
2,442
|
|
$
|
71,713
|
|
|
$
|
67,627
|
|
$
|
1,723
|
|
$
|
69,350
|
|
Transportation Expenses
|
(6,105
|
)
|
(112
|
)
|
(6,217
|
)
|
|
(6,348
|
)
|
(27
|
)
|
(6,375
|
)
|
|
63,166
|
|
2,330
|
|
65,496
|
|
|
61,279
|
|
1,696
|
|
62,975
|
|
Operating Expenses
|
(16,994
|
)
|
(754
|
)
|
(17,748
|
)
|
|
(14,921
|
)
|
(2,837
|
)
|
(17,758
|
)
|
Operating Netback
(1)
|
$
|
46,172
|
|
$
|
1,576
|
|
$
|
47,748
|
|
|
$
|
46,358
|
|
$
|
(1,141
|
)
|
$
|
45,217
|
|
|
|
|
|
|
|
|
|
U.S. Dollars Per BOE
|
|
|
|
|
|
|
|
Brent
|
|
|
$
|
45.52
|
|
|
|
|
$
|
61.70
|
|
WTI
|
|
|
$
|
45.59
|
|
|
|
|
$
|
57.87
|
|
|
|
|
|
|
|
|
|
Oil and Gas Sales
|
$
|
35.23
|
|
$
|
33.20
|
|
$
|
35.15
|
|
|
$
|
51.02
|
|
$
|
46.92
|
|
$
|
50.91
|
|
Transportation Expenses
|
(3.10
|
)
|
(1.52
|
)
|
(3.05
|
)
|
|
(4.79
|
)
|
(0.74
|
)
|
(4.68
|
)
|
|
32.13
|
|
31.68
|
|
32.1
|
|
|
46.23
|
|
46.18
|
|
46.23
|
|
Operating Expenses
|
(8.64
|
)
|
(10.25
|
)
|
(8.70
|
)
|
|
(11.26
|
)
|
(77.26
|
)
|
(13.04
|
)
|
Operating Netback
(1)
|
$
|
23.49
|
|
$
|
21.43
|
|
$
|
23.40
|
|
|
$
|
34.97
|
|
$
|
(31.08
|
)
|
$
|
33.19
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
Six Months Ended June 30, 2015
|
(Thousands of U.S. Dollars)
|
Colombia
|
Brazil
|
Total
|
|
Colombia
|
Brazil
|
Total
|
Oil and Natural Gas Sales
|
$
|
125,571
|
|
$
|
3,545
|
|
$
|
129,116
|
|
|
$
|
141,694
|
|
$
|
3,887
|
|
$
|
145,581
|
|
Transportation Expenses
|
(18,361
|
)
|
(184
|
)
|
(18,545
|
)
|
|
(15,030
|
)
|
(118
|
)
|
(15,148
|
)
|
|
107,210
|
|
3,361
|
|
110,571
|
|
|
126,664
|
|
3,769
|
|
130,433
|
|
Operating Expenses
|
(36,158
|
)
|
(657
|
)
|
(36,815
|
)
|
|
(36,213
|
)
|
(4,206
|
)
|
(40,419
|
)
|
Operating Netback
(1)
|
$
|
71,052
|
|
$
|
2,704
|
|
$
|
73,756
|
|
|
$
|
90,451
|
|
$
|
(437
|
)
|
$
|
90,014
|
|
|
|
|
|
|
|
|
|
U.S. Dollars Per bbl
|
|
|
|
|
|
|
|
Brent
|
|
|
$
|
39.61
|
|
|
|
|
$
|
57.81
|
|
WTI
|
|
|
$
|
39.52
|
|
|
|
|
$
|
53.25
|
|
|
|
|
|
|
|
|
|
U.S. Dollars Per BOE
|
|
|
|
|
|
|
|
Oil and Natural Gas Sales
|
$
|
29.70
|
|
$
|
28.19
|
|
$
|
29.65
|
|
|
$
|
47.03
|
|
$
|
40.77
|
|
$
|
46.84
|
|
Transportation Expenses
|
(4.34
|
)
|
(1.46
|
)
|
(4.26
|
)
|
|
(4.99
|
)
|
(1.24
|
)
|
(4.88
|
)
|
|
25.36
|
|
26.73
|
|
25.39
|
|
|
42.04
|
|
39.53
|
|
41.96
|
|
Operating Expenses
|
(8.55
|
)
|
(5.22
|
)
|
(8.46
|
)
|
|
(12.02
|
)
|
(44.12
|
)
|
(13.00
|
)
|
Operating Netback
(1)
|
$
|
16.81
|
|
$
|
21.51
|
|
$
|
16.93
|
|
|
$
|
30.02
|
|
$
|
(4.59
|
)
|
$
|
28.96
|
|
(1)
Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to non-GAAP measures disclosure above regarding this measure.
Oil and gas sales
for the
three months ended June 30, 2016
,
increase
d by
3%
to
$71.7 million
from
$69.4 million
in the comparable period in
2015
. The effect of
decrease
d realized oil prices was more than offset by
higher
sales volumes. Oil and gas sales for the
six months ended June 30, 2016
,
decrease
d by
11%
to
$129.1 million
from
$145.6 million
in the comparable period in
2015
primarily due to the effect of
decrease
d realized oil prices, partially offset by
higher
sales volumes.
Average realized prices for the three and
six months ended June 30, 2016
,
decrease
d by
31%
to
$35.15
per BOE
,
and by
37%
to
$29.65
per BOE, respectively, from
$50.91
and
$46.84
per BOE, respectively, in the corresponding periods in
2015
.
These price
decrease
s were primarily due to lower benchmark oil prices. Average Brent oil prices for the three and
six months ended June 30, 2016
,
decrease
d by
26%
to
$45.52
per bbl, and by
31%
to
$39.61
per bbl, respectively, compared with
$61.70
and
$57.81
per bbl, respectively, in the corresponding periods in
2015
. Average WTI oil prices for the three and
six months ended June 30, 2016
,
decrease
d by
21%
to
$45.59
and by
26%
to
$39.52
per bbl, respectively, compared with
$57.87
and
$53.25
per bbl, respectively, in the corresponding periods in
2015
.
During periods of OTA pipeline disruptions, we have multiple transportation alternatives. Each transportation route has varying effects on realized prices and transportation costs. During the three and
six months ended June 30, 2016
,
47%
and
49%
, respectively, of our oil volumes sold in Colombia were sold through the OTA pipeline compared with
75%
and
78%
, respectively, in the corresponding periods in
2015
. Sales during the
six months ended June 30, 2016
, reflected an inventory decrease in Ecuador of
270
Mbbl.
Oil and gas sales for the
three months ended June 30, 2016
,
increase
d by
25%
to
$71.7 million
from
$57.4 million
compared with the prior quarter primarily due to
higher
realized prices, partially offset by
lower
sales volumes. Average realized prices
increase
d by
42%
to
$35.15
per BOE for the
three months ended June 30, 2016
, compared with
$24.81
per BOE in the prior quarter, primarily due to
higher
benchmark oil prices. Average Brent oil prices for the
three months ended June 30, 2016
, were
$45.52
per bbl, compared with
$33.70
per bbl, in the prior quarter, a
35%
increase
. During the prior quarter,
54%
of our oil volumes sold in Colombia were sold through the OTA pipeline compared with
47%
in the current quarter.
Transportation expenses
for the
three months ended June 30, 2016
decrease
d by
2%
to
$6.2 million
compared with the corresponding period in
2015
. The
decrease
was due to
decrease
d transportation expenses per BOE, partially offset by
higher
sales volumes. On a per BOE basis, transportation expenses
decrease
d by
35%
to
$3.05
per BOE from
$4.68
per BOE in the corresponding period in
2015
. The
decrease
was a result of trucking more barrels due to higher realized sales prices.
Transportation expenses for the
six months ended June 30, 2016
,
increase
d by
22%
to
$18.5 million
compared with the corresponding period in
2015
. The
increase
in the
six months ended June 30, 2016
was due to
decrease
d transportation expenses per BOE being more than offset by
higher
sales volumes. On a per BOE basis, transportation expenses
decrease
d by
13%
to
$4.26
per BOE from
$4.88
per BOE in the corresponding period in
2015
. The
decrease
was primarily due to the alternative transportation routes used during periods of OTA pipeline disruptions.
Transportation expenses for the
three months ended June 30, 2016
,
decrease
d
50%
to
$6.2 million
compared to
$12.3 million
in the prior quarter. The effect of
decrease
d transportation costs per BOE combined with
lower
sales volumes. On a per BOE basis, transportation expenses
decrease
d by
43%
to
$3.05
per BOE from
$5.33
per BOE in the prior quarter. The
decrease
was primarily due to a higher percentage of sales at the wellhead,
48%
in the
three months ended June 30, 2016
, compared with
33%
in the prior quarter.
Operating expenses
for the three and
six months ended June 30, 2016
, were comparable at
$17.7 million
and
decrease
d by
9%
to
$36.8 million
, compared with the corresponding periods in
2015
. The
decrease
was primarily due to
decrease
d operating costs per BOE, partially offset by
higher
sales volumes. On a per BOE basis, operating expenses
decrease
d by
33%
to
$8.70
per BOE from
$13.04
per BOE and
decrease
d by
35%
to
$8.46
per BOE from
$13.00
per BOE, in the corresponding periods in
2015
.
In Colombia, operating costs for the three and
six months ended June 30, 2016
decrease
d by
$2.62
per BOE and
$3.47
per BOE compared with the corresponding periods in
2015
, primarily as a result of cost saving measures.
In Brazil in the
six months ended June 30, 2016
, we reduced the value of a contingent loss by
$0.4 million
, or
$3.31
per bbl based on volumes sold in Brazil, after we settled a one-time penalty for less than we had estimated. The one-time penalty related to alleged non-compliance with certain requirements regarding the health and safety management system, identified during a safety and operational audit conducted by the ANP in early 2015. Additionally, in Brazil operating costs per BOE decreased as a result of a reduction in headcount, partially offset by the effect of the weakening the U.S. dollar against the local currency in Brazil, which resulted in higher costs for costs denominated in local currency.
Operating expenses
decreased
by
7%
to
$17.7 million
in the
three months ended June 30, 2016
, compared with
$19.1 million
in the prior quarter primarily due to
lower
sales volumes, partially offset by the effect of
increase
d operating costs per BOE. On a per BOE basis, operating expenses
increase
d by
6%
to
$8.70
per BOE for the
three months ended June 30, 2016
, from
$8.24
per BOE in the prior quarter. Due to low commodity prices in the first half of 2016, we deferred multiple workovers until the second half of 2016. Whilst there is an impact on working interest production, we believe we will maximize returns by electing to defer workovers.
DD&A expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2016
|
|
Three Months Ended June 30, 2015
|
|
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
|
$
|
30,458
|
|
$
|
15.49
|
|
|
$
|
37,061
|
|
$
|
27.96
|
|
Brazil
|
1,024
|
|
13.92
|
|
|
1,575
|
|
42.89
|
|
Peru
|
71
|
|
—
|
|
|
147
|
|
—
|
|
Corporate
|
331
|
|
—
|
|
|
405
|
|
—
|
|
|
$
|
31,884
|
|
$
|
15.63
|
|
|
$
|
39,188
|
|
$
|
28.77
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
Six Months Ended June 30, 2015
|
|
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
|
$
|
66,194
|
|
$
|
15.65
|
|
|
$
|
83,316
|
|
$
|
27.65
|
|
Brazil
|
1,742
|
|
13.85
|
|
|
3,836
|
|
40.24
|
|
Peru
|
212
|
|
—
|
|
|
414
|
|
—
|
|
Corporate
|
648
|
|
—
|
|
|
762
|
|
—
|
|
|
$
|
68,796
|
|
$
|
15.80
|
|
|
$
|
88,328
|
|
$
|
28.42
|
|
DD&A expenses for the three and
six months ended June 30, 2016
,
decrease
d to
$31.9 million
(
$15.63
per BOE) and
$68.8 million
(
$15.80
per BOE) from
$39.2 million
(
$28.77
per BOE) and
$88.3 million
(
$28.42
per BOE) in the corresponding periods in
2015
. 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
decrease
d by
2%
to
$15.63
per BOE for the
three months ended June 30, 2016
, from
$15.95
per BOE in the prior quarter.
Asset impairment
We follow the full cost method of accounting for our oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices 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. In accordance with GAAP, we used an average Brent price of
$44.48
per bbl for the purposes of the
June 30, 2016
, ceiling test calculations (
March 31, 2016
-
$48.79
;
December 31, 2015
-
$54.08
).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
(Thousands of U.S. Dollars)
|
|
2016
|
2015
|
|
2016
|
2015
|
Impairment of oil and gas properties
|
|
|
|
|
|
|
Colombia
|
|
$
|
78,208
|
|
$
|
—
|
|
|
$
|
132,776
|
|
$
|
—
|
|
Brazil
|
|
14,152
|
|
25,000
|
|
|
15,402
|
|
29,333
|
|
Peru
|
|
483
|
|
5,285
|
|
|
899
|
|
37,966
|
|
|
|
$
|
92,843
|
|
$
|
30,285
|
|
|
$
|
149,077
|
|
$
|
67,299
|
|
Impairment of inventory
|
|
—
|
|
—
|
|
|
664
|
|
—
|
|
|
|
$
|
92,843
|
|
$
|
30,285
|
|
|
$
|
149,741
|
|
$
|
67,299
|
|
In the three and
six months ended June 30, 2016
, and
2015
, ceiling test impairment losses in our Colombia and Brazil cost centers and inventory impairment were primarily due to lower oil prices. Impairment losses in our Peru cost center related to costs incurred on Block 95.
G&A expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
(Thousands of U.S. Dollars)
|
|
2016
|
|
2016
|
2015
|
% Change
|
|
2016
|
2015
|
% Change
|
G&A Expenses
|
|
$
|
8,286
|
|
|
$
|
7,975
|
|
$
|
10,298
|
|
(23
|
)
|
|
$
|
16,261
|
|
$
|
17,592
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Dollars Per BOE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A Expenses
|
|
$
|
3.58
|
|
|
$
|
3.91
|
|
$
|
7.56
|
|
(48
|
)
|
|
$
|
3.73
|
|
$
|
5.66
|
|
(34
|
)
|
G&A expenses before stock-based compensation and capitalized G&A and overhead recoveries for the three and
six months ended June 30, 2016
,
decrease
d by
15%
to
$14.8 million
and by
25%
to
$28.3 million
, respectively, from
$17.3 million
and
$37.6 million
, respectively, in the corresponding periods in
2015
as a result of reductions in the number of our employees, commitment to cost control including focusing on all of our other G&A expenses, and the effect of the stronger U.S. dollar against the local currency in Colombia and Canada during the
three months ended June 30, 2016
, compared with the corresponding period in 2015 which resulted in savings for costs denominated in local currency. G&A expenses in the
six months ended June 30, 2016
, included
$1.3 million
of costs relating to the acquisition of Petroamerica.
After stock-based compensation and capitalized G&A and overhead recoveries, G&A expenses for the three and
six months ended June 30, 2016
,
decrease
d by
23%
to
$8.0 million
(
$3.91
per BOE) and by
8%
to
$16.3 million
(
$3.73
per BOE), respectively, from
$10.3 million
(
$7.56
per BOE) and
$17.6 million
(
$5.66
per BOE), respectively, in the corresponding periods in
2015
. The
decrease
was mainly due to the cost control initiatives referred to above, partially offset by lower allocations to capital projects due to lower capital activity. Additionally, G&A expenses in the corresponding six month period in 2015 were net of a credit of
$1.7 million
relating to the reversal of stock-based compensation expense for unvested stock options and RSUs associated with terminated employees.
G&A expenses for the
three months ended June 30, 2016
,
decrease
d by
4%
to
$8.0 million
(
$3.91
per BOE) compared with
$8.3 million
(
$3.58
per BOE) in the prior quarter. The
decrease
was primarily due to higher allocations to recoveries and capital projects, partially offset by an increase in the number of our employees and higher stock-based compensation expense.
Severance expenses
For the three and
six months ended June 30, 2016
, severance expenses were
$0.3 million
and
$1.3 million
, compared with
$2.0 million
and
$6.4 million
in the corresponding periods in
2015
. Severance expenses were consistent with the decrease in headcount.
Equity tax expense
For the
six months ended June 30, 2016
, and
2015
equity tax expense of
$3.1 million
and
$3.8 million
, respectively, represented a Colombian tax which was calculated based on our Colombian legal entities' balance sheet equity for tax purposes at January 1. The legal obligation for each year's equity tax liability arises on January 1 of each year, therefore, we recognized the annual amounts of the equity tax expense in our interim unaudited condensed consolidated statement of operations during the
six months ended June 30, 2016
, and
2015
. No equity tax expense was recorded in the
three months ended June 30, 2016
and
2015
.
Foreign exchange gains and losses
For the three and
six months ended June 30, 2016
, we had foreign exchange
loss
es of
$0.8 million
and
$1.6 million
, respectively, compared with a foreign exchange
loss
of
$3.0 million
and
gain
of
$8.6 million
, respectively, in the corresponding periods in
2015
. 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
six months ended June 30, 2016
, and
2015
:
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Change in the U.S. dollar against the Colombian peso
|
weakened by
|
|
strengthened by
|
|
weakened by
|
|
strengthened by
|
4%
|
|
0.4%
|
|
7%
|
|
8%
|
Financial instrument gains and losses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Trading securities loss (gain)
|
$
|
1,380
|
|
|
$
|
(1,688
|
)
|
|
$
|
2,225
|
|
|
$
|
(2,100
|
)
|
Commodity price derivative gain
|
(1,334
|
)
|
|
—
|
|
|
(1,334
|
)
|
|
—
|
|
Foreign currency derivatives (gain) loss
|
(1,118
|
)
|
|
322
|
|
|
(1,118
|
)
|
|
692
|
|
|
$
|
(1,072
|
)
|
|
$
|
(1,366
|
)
|
|
$
|
(227
|
)
|
|
$
|
(1,408
|
)
|
Trading securities gains and losses related to unrealized gain and losses on the Madalena Energy Inc. shares we received in connection with the sale of our Argentina business unit in June 2014.
During the three months ended June 30, 2016, we entered into commodity price derivative contracts to manage the variability cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending. We also entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs. In 2015, foreign currency derivative gains and losses related to our Colombian peso non-deliverable forward contracts which were purchased for purposes of fixing the exchange rate at which we would purchase or sell Colombian pesos to settle our income tax installments and payments.
Income tax expense and recovery
For the three and
six months ended June 30, 2016
, income tax
recovery
was
$22.8 million
and
$48.0 million
, respectively, compared with income tax expense of
$0.8 million
and
$0.9 million
, respectively, in the corresponding periods in
2015
. The income tax
recovery
for the three and
six months ended June 30, 2016
, was primarily due to ceiling test impairment losses in Colombia. The income tax
recovery
for the three and
six months ended June 30, 2016
, included
$31.3 million
and
$53.1 million
, respectively, associated with ceiling test impairment losses in Colombia. In the three and
six months ended June 30, 2015
, income tax recovery associated with impairment losses in Peru and Brazil was offset by a full valuation allowance.
The effective tax rate was
31%
in the
six months ended June 30, 2016
, compared with
(1)%
in the corresponding period in
2015
. The change in the effective tax rate for the
six months ended June 30, 2016
, was primarily due to decreases in the valuation allowance, the impact of foreign taxes, foreign currency translation adjustments and other permanent differences.
For the
six months ended June 30, 2016
, the difference between the effective tax rate of
31%
and the 35% U.S. statutory rate was primarily due to an increase in the valuation allowance, which was largely attributable to impairment losses in Brazil, as well as non-deductible local taxes, stock based compensation and a third-party royalty in Colombia. These items were partially offset by the impact of foreign taxes, foreign currency translation adjustments and other permanent differences, which mainly relates to non-taxable gain arising on the acquisition of Petroamerica and uncertain tax position adjustments, partially offset by prior periods true-up adjustments and other non-deductible expenses. For the
six months ended June 30, 2015
, the difference between the effective tax rate of
(1)%
and the 35% U.S. statutory rate was primarily due to other local taxes, an increase in the valuation allowance and the non-deductible third party royalty in Colombia, which were partially offset by the impact of foreign taxes and other permanent differences.
Funds flow from operations (a non-GAAP liquidity measure)
For the three and
six months ended June 30, 2016
, funds flow from operations
increase
d by
35%
to
$33.8 million
and
decrease
d by
16%
to
$45.3 million
, respectively, compared with the corresponding periods in
2015
.
For the
three months ended June 30, 2016
, our funds flow from operations
increase
d due to
increase
d oil and natural gas sales,
lower
transportation, G&A, severance,
lower
r
ealized foreign exchange
loss
es of
$0.5 million
, compared with
$2.5 million
in the corresponding period
and the absence of cash settlement of financial instruments
,
were partially offset by
higher
interest expenses
.
For the
six months ended June 30, 2016
,
our funds flow from operations was negatively impacted by equity tax of
$3.1 million
, realized foreign exchange
loss
es of
$1.5 million
, transaction costs of
$1.3 million
and severance expenses of
$1.3 million
.
Lower
oil and natural gas sales,
higher
transportation and interest expenses and realized foreign exchange
loss
es, were partially offset by
lower
operating, G&A, severance, equity tax and income tax expenses and the absence of cash settlement of financial instruments.
2016
Capital Program
On May 31, 2016, we announced an
increase
to our
2016
capital budget of
$33 million
to
$43 million
for a revised total of
$140 million
to
$150 million
. Our previously announced base capital budget was
$107 million
. We expect that the
increase
d capital budget will be entirely directed towards exploration in Colombia.
We expect to finance our
2016
capital program through cash flows from operations and cash on hand, while retaining financial flexibility to undertake further development opportunities and opportunistically pursue acquisitions.
Capital expenditures for the
six months ended June 30, 2016
, were
$44.6 million
compared with
$91.3 million
for the
six months ended June 30, 2015
. In the
six months ended June 30, 2016
,
82%
of our capital expenditures were incurred in Colombia.
Capital Expenditures - Colombia
Capital expenditures in our Colombian segment during the
three months ended June 30, 2016
, were
$14.5 million
. The significant elements of our
second
quarter
2016
capital program in Colombia were:
|
|
•
|
On the Chaza Block (100% working interest ("WI"), operated), we drilled and completed the Moqueta 22 development well, which was completed as an oil producer. We also commenced civil works for the Cumplidor-1 well on the Putumayo-7 Block (100% WI, operated).
|
|
|
•
|
We continued facilities work at the Moqueta Field on the Chaza Block.
|
Capital Expenditures – Brazil
Capital expenditures in our Brazilian segment during the
three months ended June 30, 2016
, were
$2.2 million
. In the
second
quarter of
2016
, we completed a workover on the 1-GTE-7HPC-BA well to assess potential as a water source well.
Capital Expenditures – Peru
Capital expenditures in our Peruvian segment for the
three months ended June 30, 2016
, were
$1.1 million
, and included
$0.3 million
on Block 95 and
$0.8 million
on our other blocks in Peru. In the
second
quarter of
2016
, operations in Peru continued to focus on maintaining tangible asset integrity and security of our five blocks in Peru (95, 107 and 133, 123 and 129) and moving forward with environmental approvals on Blocks 107 and 133 (100% WI, operated).
Liquidity and Capital Resources
At
June 30, 2016
, we had working capital of
$210.8 million
compared with
$160.4 million
at
December 31, 2015
. Working capital included cash and cash equivalents of
$171.5 million
and restricted cash of
$9.7 million
, compared with
$145.3 million
of cash and cash equivalents and restricted cash of
$0.1 million
at
December 31, 2015
.
We believe that our cash resources, including cash on hand and cash generated from operations, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for
2016
, given current oil price trends and production levels. In accordance with our investment policy, cash balances are held in our primary cash management bank in interest earning current accounts or are 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.
Notes
On April 6, 2016, we issued
$115.0 million
aggregate principal amount of our Notes in a private placement to qualified institutional buyers. The Notes bear interest at a rate of
5.00%
per year, payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2016. The Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted.
The Notes are convertible at the option of the holder at any time prior to the close of business on the business day immediately preceding the maturity date. The conversion rate is initially
311.4295
shares of Common Stock per
$1,000
principal amount of Notes (equivalent to an initial conversion price of approximately
$3.21
per share of Common Stock). The conversion rate is subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such a corporate event in certain circumstances.
We may not redeem the Notes prior to April 5, 2019, except in certain circumstances following a fundamental change as defined in the indenture governing the Notes). We may redeem for cash all or any portion of the Notes, at our option, on or after April 5, 2019, if (terms used below are as defined in the indenture governing the Notes):
(i) the last reported sale price of our Common Stock has been at least
150%
of the conversion price then in effect for at least
20
trading days (whether or not consecutive) during any
30
consecutive trading day period (including the last trading day of such period) ending on, and including, the trading day immediately preceding the date on which we provide notice of redemption; and
(ii) we have filed all reports that we are required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, as applicable (other than current reports on Form 8-K), during the twelve months preceding the date on which we provide such notice.
The redemption price will be equal to
100%
of the principal amount of the Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. No sinking fund is provided for the Notes.
If we undergo a fundamental change, holders may require us to repurchase for cash all or any portion of their Notes at a fundamental change repurchase price equal to 100% of the principal amount of the Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.
PetroLatina Acquisition Agreement
As disclosed above, on June 30, 2016, Gran Tierra Energy International Holdings Ltd., a wholly-owned subsidiary of the Company, entered into the Acquisition Agreement to acquire all of the issued and outstanding common shares of PetroLatina for cash consideration of
$525.0 million
, subject to customary working capital and other adjustments. Funding for the Acquisition will consist of an initial payment of
$500 million
at closing and a deferred payment of
$25.0 million
to be paid prior to December 31, 2016. The Acquisition is also subject to customary closing conditions, including, among other things, any required regulatory approval. Approval from the ANH was received on July 29, 2016 and the Acquisition is expected to close prior to August 31, 2016.
On July 8, 2016, we issued approximately
57.8 million
Subscription Receipts in a private placement to eligible purchasers at a price of
$3.00
per Subscription Receipt for gross proceeds of approximately
$173.5 million
. Each Subscription Receipt will entitle the holder to automatically receive one common share of Gran Tierra upon closing of the Acquisition upon the satisfaction of certain conditions. The gross proceeds from the sale of the Subscription Receipts will be held in escrow until the Acquisition close date and will be recorded as restricted cash by the Company.
We expect to fund the Acquisition through a combination of our current cash balance, gross proceeds of
$173.5 million
from the Subscription Receipts, available borrowings under our existing revolving loan and
$130.0 million
of borrowings under a new term loan that is contingent upon the closing of the Acquisition. For further information regarding the Acquisition, please see “Risk Factors - The acquisition of PetroLatina may not be completed, and even if the acquisition is completed, we may fail to realize the benefits anticipated as a result of the acquisition.”
Credit Facility
We have a credit facility with a syndicate of lenders. Availability under the credit facility is determined by a proven reserves-based borrowing base, and remains subject to the satisfaction of conditions precedent set forth in the credit agreement. Loans under the credit agreement are scheduled to mature on September 18, 2018. On June 2, 2016, we entered into a Second Amendment (the "Second Amendment") to our credit agreement dated September 18, 2015 (the "credit facility"). Pursuant to the Second Amendment, among other things, t
he committed borrowing base under our credit facility was reduced from
$200 million
to
$185 million
, with
$160 million
readily available and
$25 million
subject to the consent of all lenders. Further, the amount of permitted senior debt under the Company's credit facility was decreased from
$600 million
to
$500 million
.
The borrowing base will be re-determined semi-annually based on reserve evaluation reports, subject to a maximum of
$500 million
. The next borrowing base redetermination is in late November 2016. The borrowing base for the credit facility is supported by the present value of the petroleum reserves of our subsidiaries with operating branches in Colombia. The credit agreement includes a letter of credit sub-limit of up to
$100 million
. Amounts drawn down under the facility bear interest, at our option, at the USD LIBOR rate plus a margin ranging from
2.00%
per annum to
3.00%
per annum, or an alternate base rate plus a margin ranging from
1.00%
per annum to
2.00%
per annum, in each case based on the borrowing base utilization percentage. Undrawn amounts under the credit facility bear interest at
0.75%
per annum, based on the average daily amount of unused commitments. A letter of credit participation fee of
0.25%
per annum will accrue on the average daily amount of letter of credit exposure.
Under the terms of the 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 ("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 December 31, 2015, we were in compliance with all financial and operating covenants in our credit agreement. As of
June 30, 2016
, no amounts have been drawn on this facility. 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 Canada and the United States
At
June 30, 2016
,
32%
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. As noted above, during the three months ended June 30, 2016, our parent company in the United States received net proceeds of
$108.9 million
from the Notes offering and this significantly increased the percentage of cash and cash equivalents held by our subsidiaries and partnerships in Canada and the United States. At this time, we do not intend to repatriate further funds, 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.
The government in Brazil requires us to register funds that enter and exit the country with its central bank. In Brazil and Colombia, all transactions must be carried out in the local currency of the country. 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.
Cash Flows
During the
six months ended June 30, 2016
, our cash and cash equivalents
increase
d by
$26.1 million
as a result of cash
provided by
operating activities of
$38.2 million
and cash
provided by
financing activities of
$114.3 million
, partially offset by cash
used in
investing activities of
$128.3 million
(including
$50.9 million
and
$19.4 million
of cash used in investing activities in relation to the Petroamerica and PGC acquisitions, respectively).
Cash
provided by
operating activities
in the
six months ended June 30, 2016
, was primarily affected by
decrease
d oil and natural gas sales,
higher
transportation expenses and realized foreign exchange
loss
es and a
$6.6 million
change in assets and liabilities from operating activities. These amounts were partially offset by
lower
operating, G&A, severance, equity tax and income tax expenses and the absence of cash settlement of financial instruments.
Cash used in investing activities
in the
six months ended June 30, 2016
, included an
increase
in restricted cash of
$2.3 million
, capital expenditures incurred of
$44.6 million
plus
$19.4 million
of cash paid for property, plant and equipment for the PGC acquisition and net cash paid for the Petroamerica acquisition of
$50.9 million
and
$11.1 million
of net cash outflows related to changes in assets and liabilities associated with investing activities. Cash used in investing activities in the
six months ended June 30, 2015
, included an
increase
in restricted cash of
$0.3 million
, capital expenditures incurred of
$91.3 million
, and net cash outflows related to changes in assets and liabilities associated with investing activities of
$77.1 million
.
Cash
provided by
financing activities
in the
six months ended
June 30, 2016
relates to
$108.9 million
of net proceeds on issuance of the Notes, net of issuance costs, and proceeds from issuance of shares of our Common Stock upon the exercise of stock options compared with solely proceeds from issuance of shares of our Common Stock upon the exercise of stock options in the corresponding period.
Off-Balance Sheet Arrangements
As at
June 30, 2016
, we had no off-balance sheet arrangements.
Contractual Obligations
During April 2016, we issued
$115.0 million
aggregate principal amount of our Notes. The Notes bear interest at a rate of
5.00%
per year, payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2016. The Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted. See Note 6 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for further information.
Except as noted above, as at
June 30, 2016
, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as of
December 31, 2015
.
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates are disclosed in Item 7 of our
2015
Annual Report on Form 10-K, filed with the SEC on
February 29, 2016
, and have not changed materially since the filing of that document, other than as follows:
Derivative Activities
During the three months ended June 30, 2016, we entered into commodity price derivative contracts to manage the variability cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending. We also entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs.
Under accounting rules, we may elect to designate certain derivative contracts that qualify for hedge accounting as hedges against the price that we will receive for our future oil and gas production. However, we do not designate any of our derivative contracts as accounting hedges. Because derivative contracts not designated for hedge accounting are accounted for on a mark-to-market basis, we are likely in the future to experience non-cash volatility in our reported net income or loss during periods of commodity price volatility.
As of
June 30, 2016
, we had derivative assets of
$7.0 million
which are classified as a Level 2 fair value measurement. The value of these contracts at their respective settlement dates could be significantly different than the fair value as of
June 30, 2016
. The fair value of commodity price and foreign currency derivatives is estimated based on various factors, including quoted market prices in active markets and quotes from third parties. We also perform an internal valuation to ensure the reasonableness of third party quotes.
For further discussion of our derivative instruments and activities, see Note 12, "Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk" to our condensed consolidated financial statements in Item 1 of this report for additional information regarding the accounting applicable to our derivative contracts, a listing of open contracts and the estimated fair market value of those contracts as of
June 30, 2016
.
Full Cost Method of Accounting and Impairments of Oil and Gas Properties
In the
six months ended June 30, 2016
, we recorded ceiling test impairment losses in our Colombia and Brazil cost centers of
$132.8 million
and
$15.4 million
, respectively, related to lower oil prices. Holding all factors constant other than benchmark oil prices, it is reasonably likely that we will experience ceiling test impairment losses in our Brazil and Colombia cost centers in the
third
quarter of
2016
.
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 believe that ceiling test impairment losses in the
third
quarter of
2016
could exceed
$5 million
in Brazil and
$92 million
in Colombia. The calculation of the impact of lower 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 pro forma Brent oil price of
$42.58
per bbl for the year ended
September 30, 2016
. These pro forma oil prices were 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
July
30,
2016
, and, for the two months ended
September 30, 2016
, estimated oil prices for the
third
quarter of
2016
using the forward price curve forecast of our independent reserves evaluator dated July 1, 2016. We used an average Brent price of
$44.48
per bbl for the purposes of the
June 30, 2016
, ceiling test calculations (
March 31, 2016
-
$48.79
;
December 31, 2015
-
$54.08
).
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. In Brazil, foreign exchange rates can materially impact operating costs and the income tax calculation.
Holding all factors constant other than benchmark oil prices and related royalty rates, we do not expect any downward adjustment to our consolidated NAR reserve volumes during the
third
quarter of
2016
. This disclosure is based on a pro forma Brent oil price of
$42.58
per bbl for the year ended
September 30, 2016
, calculated as described above.
Business Environment Outlook
Our revenues are significantly affected by the continuing fluctuations in world oil prices. Oil prices are volatile and unpredictable and are influenced by concerns about the quantity of world supply and demand fundamentals, market competition between large producers, predominately members of OPEC (Organization of Petroleum Producing Countries), for
market share, political influences, financial markets and the impact of the worldwide economy on oil supply and demand growth.
We believe that our current operations and
2016
capital expenditure program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including additional pipeline delivery restrictions in Colombia or continued downturn in oil and gas prices, we would consider financing our capital expenditure program with borrowings under our revolving credit facility, proceeds from the disposition of assets or capital markets transactions, or a combination thereof, or we would consider reducing our capital expenditure program. We are the operator in the majority of our blocks and therefore have discretion on the timing of our capital expenditures. Given the current economic environment and unstable conditions in the Middle East, North Africa, and Europe and the current over supply of oil in world markets, the oil price environment is unpredictable and unstable. We are unable to determine the impact, if any, these events may have on oil prices and demand. The timing and execution of our capital expenditure program are also affected by the availability of services from third party oil field contractors and our ability to obtain, sustain or renew necessary government licenses and permits on a timely basis to conduct exploration and development activities. Any delay may affect our ability to execute our capital expenditure program.
The credit markets, including the high yield bond market and other debt markets that provide capital to oil and gas companies have experienced adverse conditions. We have not been materially impacted by these conditions; however, continuing volatility in oil prices may continue to contribute to these adverse conditions, which could increase costs associated with renewing or issuing debt or affect our ability to access those markets.
Our future growth and acquisitions may depend on our ability to raise additional funds through equity and debt capital market transactions. Should we access such capital markets to fund capital expenditures or other acquisition and development opportunities, such funding may be affected by the market value of shares of our Common Stock. Issuing additional shares of Common Stock, or other equity securities convertible into Common Stock, may further dilute our existing shareholders. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve further pledging of some or all of our assets may require compliance with debt covenants and will expose us to interest rate risk. Depending on the currency used to borrow money, we may also be exposed to further foreign exchange risk. Our ability to borrow money and the interest rate we pay for any money we borrow will be affected by market conditions and we cannot predict what price we may pay for any borrowed money.
For over 40 years, the Colombian government has been engaged in a conflict with two main Marxist guerrilla groups: the Revolutionary Armed Forces of Colombia ("FARC") and the National Liberation Army ("ELN"). Both of these groups have been designated as terrorist organizations by the United States and the European Union. Another threat comes from criminal gangs formed from the former members of the United Self-Defense Forces of Colombia militia, a paramilitary group that originally sprouted up to combat FARC and ELN, which the Colombian government successfully dissolved. We operate principally in the Putumayo Basin in Colombia. Pipelines have been primary targets because such pipelines cannot be adequately secured due to the sheer length of such pipelines and the remoteness of the areas in which the pipelines are laid. The CENIT S.A-operated Trans-Andean oil pipeline (the "OTA pipeline”) which transports oil from the Putumayo region and which is one of our export routes, has been targeted by these guerrilla groups.
While peace talks continue between the Colombian government and the FARC, peace process negotiations between the government and FARC may not generate the intended outcome for both parties. The impact of such a peace process is not determinable on our operations. Continuing attempts by the Colombian government to reduce or prevent guerrilla activity may not be successful and guerrilla activity may continue to disrupt our operations in the future. Our efforts to increase security measures may not be successful and there can also be no assurance that we can maintain the safety of our or our contractors' field personnel and Bogota head office personnel or operations in Colombia or that this violence will not continue to adversely affect our operations in the future and cause significant loss.