4Q17 Production Beats Guidance by 14%, Approaches 100 mboepd BIRMINGHAM, Ala.
2018 Production Estimated to Grow 25% YOY at Midpoint
3-Year Production CAGR (2018-2020) Expected to Exceed 28% Per Year
****NOTE: 4Q17 conference call slides available at www.energen.com****
Energen Corporation (NYSE: EGN) (“Energen” or the “company”) today
announced financial and operating results for the fourth quarter ended
December 31, 2017.
FINANCIAL AND OPERATING HIGHLIGHTS
STRONG EXECUTION DRIVES STRONG 4Q17 AND CY17
-
4Q17 production of 97.4 mboepd exceeded guidance by 14% and
surpassed 3Q17 production by 20%.
-
4Q17 oil production of 58.1 mbopd exceeded guidance by 8% and
surpassed 3Q17 oil production by 19%.
-
CY17 production of 76.1 mboepd grew 39% from CY16 on strength of
Generation 3 completions and greater activity level.
-
4Q17 adjusted EBITDAX of $241 mm grew 39% from 3Q17 and beat
internal expectations by 24%.
-
Per-unit LOE and net SG&A beat guidance midpoints by 10% and 9%,
respectively.
-
Additions in 2017 replaced production by ≈415%, driving 40%
increase in YE17 proved reserves.
-
CY17 proved developed F&D cost totaled $8.38/boe.
-
Updated inventory supports net undeveloped resource potential of
2.7 billion BOE.
GEN 3 PATTERN WELLS CONTINUE TO GENERATE
OUTSTANDING RESULTS
-
Gen 3 performance drives strong IRRs through higher EURs and/or
acceleration.
-
Updated type curves support superior economics.
-
25 gross/21 net wells turned to production in 4Q17; 64% were
multi-zone pattern wells completed in batches.
-
New wells reflect outstanding 24-hr. and 30-day IP rates in Midland
and Delaware basins; 4Q17 Delaware Basin wells generated average
24-hour IP rate of 402 boepd/1,000’ and average 30-day IP rate of 272
boepd/1,000’.
BRINGING VALUE FORWARD IN CY18
-
Drilling and development capital (including facilities) estimated
to range from $1.1 billion to $1.3 billion.
-
Annual production estimated to range from 91.5-98.5 mboepd.
-
Capital plans include drilling approximately 130 gross/120 net
horizontal wells and completing approximately 123 gross/113 net
horizontal wells (including 30 gross/28 net DUCs at YE17).
3-YEAR OUTLOOK (2018-2020) LEVERAGES
SUPERIOR ECONOMICS TO FURTHER DRIVE SHAREHOLDER VALUE
-
Annual oil production estimated to grow at 3-year CAGR of ≈28%.
-
Annual production estimated to reach ≈160 mboepd in 2020, with 4Q
exit rate of ≈170 mboepd.
-
Drilling and development capital estimated to increase to $1.6-$1.8
billion in 2020.
-
YE20 EBITDAX estimated to be ≈$1.6 billion (3-year CAGR: ≈35%).
-
Balance sheet ensures capital flexibility as net debt to EBITDAX
expected to remain between 1.0x-1.5x.
Comments from the CEO
“Energen’s breakout year of 2017 culminated with another excellent
quarter of execution, growth, and financial strength,” said Energen
Chief Executive Officer James McManus. “In the 4th
quarter as well as the year, we delivered on our drilling and
development plans and exceeded expectations for oil and total production
as well as for lease operating and net SG&A expenses.
“As a result of implementing a clearly-defined strategy based on
decisions made by the company’s Board and management, Energen is poised
to build on its strong performance in 2017. Over the last five years,
the Board and management have strategically divested non-core assets and
transformed Energen into a low-cost Permian pure-pay with a strong
foundation for profitable growth. As we look out over the next three
years, we plan to leverage the superior economics of our Permian Basin
assets in the Delaware and Midland basins to further drive shareholder
value.
“We begin 2018 with a portfolio of high quality, oil-focused assets
in the Delaware and Midland basins,” McManus said. “The company is
delivering strong returns with the continued implementation of
Generation 3 frac designs that are driving significant production
growth. At the same, the company remains focused on cost reductions and
operating efficiencies and a strong balance sheet that supports growth,
capital flexibility, and value creation,” he added.
“Our Gen 3 frac designs are generating strong internal rates of
return through higher EURs and/or acceleration, and we estimate that we
can generate a 3-year compound annual growth rate (2018-2020) in excess
of 28 percent a year while maintaining a net debt to EBITDAX multiple
between 1.0x and 1.5x,” McManus said.
“We are extremely pleased with our performance this quarter and
confident that Energen is well-positioned to continue delivering strong
results and creating shareholder value.”
4Q17 Operations Update
In 4Q17 Energen turned to production 20 gross (16 net) wells in the
Midland Basin and 5 gross (5 net) wells in the Delaware Basin. Their
early performance continues to reflect outstanding results from Gen 3
frac designs; 64 percent were multi-zone pattern wells completed in
batches. During the quarter, Energen operated 6 horizontal drilling rigs
and 2 frac crews.
4Q17 Wells Turned to Production
|
|
|
|
|
|
|
|
|
Area
|
|
# Wells
|
|
Avg. Completed Lateral Length
|
|
Avg. Peak 24-Hr IP
|
|
Avg. Peak 30-Day IP
|
|
|
|
Boepd
|
|
Boepd/ 1,000’
|
|
% Oil
|
|
Boepd
|
|
Boepd/ 1,000’
|
|
% Oil
|
Delaware Basin
|
|
5
|
|
Wolfcamp A (4) 3rd BS Sand (1)
|
|
6,297’
|
|
2,529
|
|
402
|
|
74
|
|
1,716
|
|
272
|
|
73
|
N. Midland Basin
|
|
4
|
|
Wolfcamp A (2) Wolfcamp B (2)
|
|
7,548‘
|
|
1,469
|
|
195
|
|
90
|
|
1,020
|
|
135
|
|
84
|
N. Midland Basin
|
|
5
|
|
Lower Spraberry
|
|
7,451‘
|
|
1,779
|
|
239
|
|
93
|
|
1,425
|
|
191
|
|
90
|
N. Midland Basin *
|
|
9
|
|
M. Spraberry (5) Jo Mill (4)
|
|
7,964‘
|
|
867
|
|
109
|
|
89
|
|
676
|
|
85
|
|
86
|
C. Midland Basin
|
|
2
|
|
Wolfcamp A
|
|
9,160‘
|
|
1,766
|
|
193
|
|
91
|
|
1,159
|
|
126
|
|
82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Includes a Middle Spraberry well and a Jo Mill well
turned to production in late 3Q17 but not previously disclosed due
to timing of first production
|
|
Note: 2 test wells drilled in other formations in the Midland
Basin are not included
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4Q17 Financial Results
For the 3 months ended December 31, 2017, Energen reported GAAP net
income from all operations of $262.4 million, or $2.68 per diluted
share. Adjusting for a non-cash loss on mark-to-market derivatives of
$(37.5 million); a one-time, non-cash tax benefit of $240.1 million
resulting from the Tax Cuts and Jobs Act; and miscellaneous non-cash
items totaling $(1.4) million: Energen had adjusted net income in 4Q17
of $61.3 million, or $0.63 per diluted share. This compares with an
adjusted net loss in 4Q16 of $(26.6 million), or $(0.27) per diluted
share. [See “Non-GAAP Financial Measures” beginning on p. 10 for more
information and reconciliation.]
Energen’s adjusted 4Q17 net income of $61.3 million exceeded internal
expectations by $28.6 million largely due to better-than-expected
production; lower-than-expected depreciation, depletion and amortization
expense (DD&A), lease operating expense (LOE), and net salaries and
general and administrative expense (SG&A); and higher realized oil
prices.
Energen’s adjusted EBITDAX in 4Q17 totaled $241.0 million; this was 39
percent higher than adjusted EBITDAX in 3Q17 and 24 percent above
internal expectations. In the same period a year ago, Energen’s adjusted
EBITDAX totaled $82.1 million. [See “Non-GAAP Financial Measures”
beginning on p. 10 for more information and reconciliation.]
4Q17 Production (mboepd)
|
|
|
|
|
|
|
Commodity
|
|
4Q17
|
|
Actual
|
|
Guidance
|
|
% ∆
|
Oil
|
|
58.1
|
|
54.0
|
|
8
|
NGL
|
|
19.4
|
|
14.9
|
|
30
|
Natural Gas
|
|
20.0
|
|
16.8
|
|
19
|
Total
|
|
97.4
|
|
85.7
|
|
14
|
|
|
|
|
|
|
|
Area
|
|
4Q17
|
|
Actual
|
|
Guidance
|
|
% ∆
|
Midland Basin
|
|
51.7
|
|
45.4
|
|
14
|
Delaware Basin
|
|
37.4
|
|
32.4
|
|
15
|
Platform/Other
|
|
8.2
|
|
7.8
|
|
5
|
Total
|
|
97.4
|
|
85.7
|
|
14
|
|
|
|
|
|
|
|
Note: Totals may not sum due to rounding.
|
|
|
|
|
|
|
|
4Q17 Expenses
|
|
|
Per BOE, except where noted
|
|
4Q17
|
|
Actual
|
|
Guidance Mdpt
|
|
% ∆
|
LOE (production costs, marketing & transportation)
|
|
$
|
6.02
|
*
|
|
$
|
6.70
|
|
|
(10
|
)
|
Production & ad valorem taxes (% of revenues exc. hedges)
|
|
|
5.3
|
%
|
|
|
6.2
|
%
|
|
(15
|
)
|
DD&A
|
|
$
|
14.43
|
|
|
$
|
16.30
|
|
|
(11
|
)
|
SG&A
|
|
$
|
2.58
|
|
|
$
|
2.85
|
|
|
(9
|
)
|
Exploration (includes seismic, delay rentals, etc.)
|
|
$
|
0.19
|
|
|
$
|
0.20
|
|
|
(5
|
)
|
Interest ($mm)
|
|
$
|
10.3
|
|
|
$
|
10.0
|
|
|
3
|
|
|
|
|
|
|
|
|
* LOE in the Midland/Delaware basins totaled $4.94/boe
|
|
|
|
|
|
|
|
4Q17 Average Realized Prices
|
|
|
|
|
Commodity
|
|
With Hedges
|
|
W/O Hedges
|
Oil (per barrel)
|
|
$
|
50.71
|
|
$
|
52.75
|
NGL (per gallon)
|
|
$
|
0.46
|
|
$
|
0.52
|
Natural Gas (per mcf)
|
|
$
|
2.25
|
|
$
|
2.08
|
|
|
|
|
|
|
|
CY17 Financial Results
For CY17, Energen reported GAAP net income from all operations of $306.8
million, or $3.14 per diluted share. Adjusting for a non-cash items,
Energen had adjusted net income in CY17 of $73.6 million, or $0.75 per
diluted share. This compares with an adjusted net loss in CY16 of
$(128.8 million), or $(1.36) per diluted share. Energen’s adjusted
EBITDAX in CY17 totaled $653.0 million – more than double the company’s
adjusted EBITDAX in CY16 of $293.2 million. [See “Non-GAAP Financial
Measures” beginning on p. 10 for more information and reconciliation.]
CY17 Production (mboepd)
|
|
|
|
|
|
|
By Commodity
|
|
CY17
|
|
CY16*
|
|
% ∆
|
Oil
|
|
46.4
|
|
34.5
|
|
34
|
|
NGL
|
|
14.4
|
|
9.4
|
|
53
|
|
Natural Gas
|
|
15.3
|
|
10.7
|
|
43
|
|
Total
|
|
76.1
|
|
54.6
|
|
39
|
|
|
|
|
|
|
|
|
By Basin
|
|
CY17
|
|
CY16*
|
|
% ∆
|
Midland Basin
|
|
42.4
|
|
35.3
|
|
20
|
|
Delaware Basin
|
|
25.6
|
|
10.3
|
|
149
|
|
Platform/Other
|
|
8.1
|
|
9.0
|
|
(10
|
)
|
Total
|
|
76.1
|
|
54.6
|
|
39
|
|
|
|
|
|
|
|
|
* Excludes 2016 asset sales
|
Note: Totals may not sum due to rounding
|
|
|
|
|
|
|
|
CY17 Expenses
|
|
|
|
|
|
|
Per BOE, except where noted
|
|
CY17
|
|
CY16*
|
|
% ∆
|
LOE (production costs, marketing & transportation)†
|
|
$
|
6.61
|
|
|
$
|
7.86
|
|
|
(16
|
)
|
Production & ad valorem taxes (% of revenues exc. hedges)
|
|
|
6.0
|
%
|
|
|
6.6
|
%
|
|
(9
|
)
|
DD&A
|
|
$
|
17.23
|
|
|
$
|
21.45
|
|
|
(20
|
)
|
SG&A
|
|
$
|
3.05
|
|
|
$
|
4.32
|
|
|
(29
|
)
|
Exploration (includes seismic, delay rentals, etc.)
|
|
$
|
0.29
|
|
|
$
|
0.27
|
|
|
7
|
|
Interest ($mm)
|
|
$
|
38.4
|
|
|
$
|
36.9
|
|
|
4
|
|
|
|
|
|
|
|
|
* Excludes 2016 asset sales
|
† LOE in the Midland and Delaware basins
totaled $5.28/boe in CY17, down 15 percent from $6.23/boe in CY16
|
|
|
|
|
|
|
|
2017 Capital
Drilling and development capital in 2017 totaled $902 million, including
$197 million in the fourth quarter. Total capital invested in 2017
including leasehold/mineral acquisitions and FF&E totaled $1.2 billion
in 2017 and $217 million in the fourth quarter. During 4Q17, Energen
added approximately 1,600 net acres of proved and unproved leasehold for
some $16 million.
Liquidity and Leverage Update
At December 30, 2017, Energen had cash of $0.4 million, long-term debt
of $527.9 million, and $255.0 million drawn on its $1.05 billion line of
credit. The company’s net debt-to-adjusted EBITDAX at year-end 2017
totaled 1.2x.
2018 Overview
Energen plans to invest $1.1 billion to $1.3 billion of capital for
drilling and development activities in 2018 (approximately $550-$650
million in each of the Delaware and Midland basins). Approximately 81
percent of the capital will be invested in drilling and developing
operated wells; some 13 percent is allocated to saltwater disposal wells
and other facilities; and the remainder is expected to be spent on
non-operated and other activities. For its unhedged volumes, Energen’s
2018 plans assume recent strip prices of $58 WTI per barrel of
oil, $0.65 per gallon of NGL, and $2.75 Henry Hub per Mcf of gas.
The company plans to drill approximately 130 gross/120 net horizontal
wells in 2018 and complete approximately 123 gross/113 net horizontal
wells, including 30 gross/28 net year-end 2017 drilled but uncompleted
wells (DUCs). The working interest of completed wells in 2018 is
approximately 90 percent, and the average lateral length is
approximately 8,000’. The company estimates its YE18 DUCs will total
approximately 37 gross/35 net. Energen also plans to drill 7 gross/7 net
vertical wells in the Midland Basin and complete 6 gross/6 net of them.
During 2018, the company plans to run an average of 9 drilling rigs and
4.5 frac crews.
Primary horizontal well targets in 2018 are the Wolfcamp A and B in the
Delaware Basin; the Jo Mill, Middle Spraberry, Lower Spraberry and
Wolfcamp A and B zones in the northern Midland Basin; and the Wolfcamp A
and B in the central Midland Basin. [See 4Q17 conference slides for
updated DC&E costs, type curves, EURs, and internal rates of return for
Energen’s 2018 program.]
2018 Production Guidance
Energen’s production in 2018 is estimated to range from 91.5-98.5
mboepd, reflecting a 25 percent increase from 2017 at midpoint.
|
|
|
|
|
|
|
|
|
Area
|
|
2018 Guidance
|
|
2018 Guidance
|
|
2017 Actual
|
|
% Change
|
|
|
Range
|
|
Midpoint
|
|
|
|
Mdpt. vs Actual
|
Midland Basin
|
|
48.5 - 51.5
|
|
50.0
|
|
42.4
|
|
18
|
Delaware Basin
|
|
37.0 - 39.0
|
|
38.0
|
|
25.6
|
|
48
|
Platform/Other
|
|
6.0 - 8.0
|
|
7.0
|
|
8.1
|
|
(14)
|
Total
|
|
91.5 - 98.5
|
|
95.0
|
|
76.1
|
|
25
|
|
|
|
|
|
|
|
|
|
NOTE: Totals may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
2018 Guidance
|
|
2018 Guidance
|
|
2017 Actual
|
|
% Change
|
|
|
Range
|
|
Midpoint
|
|
|
|
Mdpt. vs Actual
|
Oil
|
|
55.5 - 58.5
|
|
57.0
|
|
46.4
|
|
23
|
NGL
|
|
17.0 - 19.0
|
|
18.0
|
|
14.4
|
|
25
|
Gas
|
|
19.0 - 21.0
|
|
20.0
|
|
15.3
|
|
31
|
Total
|
|
91.5 - 98.5
|
|
95.0
|
|
76.1
|
|
25
|
|
|
|
|
|
|
|
|
|
NOTE: Totals may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guidance by Basin
|
|
1Q18e
|
|
|
2Q18e
|
|
|
3Q18e
|
|
|
4Q18e
|
Midland Basin
|
|
49.5 - 52.5
|
|
|
48.5 - 51.5
|
|
|
46.5 - 49.5
|
|
|
50.0 - 53.0
|
Delaware Basin
|
|
30.0 - 32.0
|
|
|
33.0 - 35.0
|
|
|
37.0 - 39.0
|
|
|
47.5 - 49.5
|
Platform/Other
|
|
6.5 - 8.5
|
|
|
6.0 - 8.0
|
|
|
6.0 - 8.0
|
|
|
6.0 - 8.0
|
Total
|
|
86.0 - 93.0
|
|
|
87.5 - 94.5
|
|
|
89.5 - 96.5
|
|
|
103.5 - 110.5
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE: Totals may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guidance by Commodity
|
|
1Q18e
|
|
|
2Q18e
|
|
|
3Q18e
|
|
|
4Q18e
|
Oil
|
|
51.5 - 54.5
|
|
|
51.5 - 54.5
|
|
|
54.0 - 57.0
|
|
|
65.0 - 68.0
|
NGL
|
|
16.5 - 18.5
|
|
|
17.0 - 19.0
|
|
|
16.5 - 18.5
|
|
|
18.0 - 20.0
|
Gas
|
|
18.0 - 20.0
|
|
|
19.0 - 21.0
|
|
|
19.0 - 21.0
|
|
|
20.0 - 22.0
|
Total
|
|
86.0 - 93.0
|
|
|
87.5 - 94.5
|
|
|
89.5 - 96.5
|
|
|
103.5 - 110.5
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE: Totals may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 First Production/Flow back (Operated Horizontal Wells –
Gross/Net)
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q18e
|
|
2Q18e
|
|
3Q18e
|
|
4Q18e
|
|
CY18e
|
Midland Basin
|
|
9/8
|
|
16/15
|
|
15/14
|
|
26/22
|
|
66/58
|
Delaware Basin
|
|
4/4
|
|
12/10
|
|
14/13
|
|
21/21
|
|
51/48
|
|
|
|
|
|
|
|
|
|
|
|
NOTE: Totals may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
2018 Expenses
Energen expects most of its per-unit expenses to continue declining
year-over-over in 2018 as production increases. LOE per boe in CY18 is
estimated to range from $5.05-$5.25 in the Midland Basin, $5.35-$5.55 in
the Delaware Basin, and $21.55-$21.75 in the Central Basin
Platform/Northeast Shelf areas (“Platform”). Net SG&A per boe in CY18 is
estimated to be comprised of cash of $1.85-$2.05 per boe and non-cash,
equity-based compensation of $0.45-$0.65 per boe.
|
|
|
|
|
Per BOE, except where noted
|
|
2018e
|
|
CY17 Actual
|
LOE (production costs, marketing & transportation)
|
|
$6.40 - $6.60
|
|
$6.61
|
Production & ad valorem taxes (% of revenues, excluding hedges)
|
|
6.2%
|
|
6.0%
|
DD&A expense
|
|
$14.00 - $14.50
|
|
$17.23
|
Salaries and general & administrative expense, net
|
|
$2.30 - $2.70
|
|
$3.05
|
Exploration expense (seismic, delay rentals, etc.)
|
|
$0.15 - $0.20
|
|
$0.29
|
Interest expense ($MM)
|
|
$46.5 - $51.5
|
|
$38.4
|
FF&E depreciation ($MM)
|
|
$4.0 - $5.0
|
|
$ 4.6
|
Accretion of discount on ARO ($MM)
|
|
$5.5 - $7.0
|
|
$5.8
|
Effective tax rate (%)
|
|
22% - 24%
|
|
37%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per BOE, except where noted
|
|
1Q18e
|
|
2Q18e
|
|
3Q18e
|
|
4Q18e
|
LOE
|
|
$6.20 - $6.40
|
|
$6.75 - $6.95
|
|
$6.55 - $6.75
|
|
$6.15 - $6.35
|
Production & ad valorem taxes*
|
|
6.4%
|
|
6.2%
|
|
6.2%
|
|
6.2%
|
DD&A expense
|
|
$14.70 - $15.20
|
|
$14.45 - $14.95
|
|
$13.85 - $14.35
|
|
$13.15 - $13.65
|
SG&A, net
|
|
$2.80 - $3.20
|
|
$2.40 - $2.80
|
|
$2.30 - $2.70
|
|
$1.80 - $2.20
|
Exploration expense
|
|
$0.15 - $0.20
|
|
$0.15 - $0.20
|
|
$0.15 - $0.20
|
|
$0.15 - $0.20
|
Effective tax rate (%)
|
|
22% - 24%
|
|
22% - 24%
|
|
22% - 24%
|
|
22% - 24%
|
|
|
|
|
|
|
|
|
|
* % of revenues, excluding hedges
|
|
|
|
|
|
|
|
|
|
3-Year Outlook
Energen’s management believes the quality of its deep inventory in the
Permian Basin supports a 3-year compound annual production growth rate
of more than 28 percent a year (2018-2020). This growth comes as Energen
maintains an outstanding balance sheet while increasing capital
investment to bring forward the value of its inventory. Energen
estimates that its annual production will grow from 95 mboepd (at
guidance midpoint) in 2018 to more than 160 mboepd in 2020 and that 4Q
production will increase from 107 mboepd (at guidance midpoint) in 2018
to approximately 135 mboepd in 2019 and 170 mboepd in 2020.
At recent strip prices, Energen estimates that its capital plans support
annual investment in drilling and development activities in a range of
$1.4-$1.6 billion in 2019 and $1.6-$1.8 billion in 2020. Energen’s
EBITDAX at year-end 2020 is estimated to be approximately $1.6 billion,
representing a 3-year CAGR of approximately 35 percent a year. (Oil
prices used in the 3-year outlook reflect recent strip prices of $58 per
barrel in 2018, $54 in 2019, and $52 in 2020).
YE17 Proved Reserves Increase 40% to 444 MMBOE
Energen’s proved reserves at year-end 2017 totaled 444 mmboe, up
approximately 40 percent from year-end 2016. Reserve additions of 115.5
mmboe replaced production by 415 percent and were driven by an active
drilling and completion program in the Midland and Delaware basins that
featured Gen 3 frac designs. Proved reserves in the Delaware Basin alone
rose 177 percent. The CY17 proved developed finding and development
(F&D) cost totaled $8.38 per boe.
Proved developed F&D per boe is defined as exploration and development
costs divided by the sum of reserves associated with discoveries and
extensions placed on production during 2017, transfers from proved
undeveloped reserves at year-end 2016, and revisions (excluding
price-related revisions) of previous estimates of proved developed
reserves in 2017.
Commodity prices used for calculating reserves at year-end 2017 were
higher than those at year-end 2016. WTI oil prices rose 20 percent to
$51.34, while NGL prices (before transportation and fractionation)
increased 46 percent to 57 cents per gallon and Henry Hub natural gas
prices increased 20 percent to 2.98 per thousand cubic feet (Mcf).
Proved Reserves by Basin (MMBOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2017
|
|
2017
|
|
|
Basin
|
|
YE16
|
|
2017
|
|
Acquisitions/
|
|
Additions
|
|
Price/Other
|
|
YE17
|
|
|
|
|
Production
|
|
(Divestitures)
|
|
|
|
Revisions
|
|
|
Midland Basin
|
|
236.4
|
|
(15.5
|
)
|
|
--
|
|
49.0
|
|
23.9
|
|
293.8
|
Delaware Basin
|
|
39.1
|
|
(9.4
|
)
|
|
0.2
|
|
66.3
|
|
11.8
|
|
108.1
|
Platform/Other
|
|
40.9
|
|
(3.0
|
)
|
|
--
|
|
0.1
|
|
4.1
|
|
41.1
|
TOTAL
|
|
316.3
|
|
(27.8
|
)
|
|
0.2
|
|
115.5
|
|
39.8
|
|
444.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE: Totals may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves by Commodity (MMBOE)
|
|
|
|
|
Commodity
|
|
2017
|
|
2016
|
Oil
|
|
257
|
|
200
|
Natural gas liquids
|
|
91
|
|
58
|
Natural gas
|
|
96
|
|
58
|
TOTAL
|
|
444
|
|
316
|
|
|
|
|
|
NOTE: Totals may not sum due to rounding
|
|
|
|
|
|
YE17 3P Reserves & Contingent Resources (MMBOE)
|
|
|
|
|
|
|
|
|
|
|
Basin
|
|
Proved
|
|
Probable
|
|
Possible
|
|
Contingent
|
|
Total
|
|
|
|
|
|
|
|
|
Resources
|
|
|
Midland Basin
|
|
294
|
|
154
|
|
130
|
|
979
|
|
1,557
|
Delaware Basin
|
|
108
|
|
40
|
|
46
|
|
1,243
|
|
1,437
|
Platform/Other
|
|
42
|
|
--
|
|
--
|
|
1
|
|
43
|
TOTAL
|
|
444
|
|
194
|
|
176
|
|
2,223
|
|
3,037
|
|
|
|
|
|
|
|
|
|
|
|
NOTE: Totals may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
The definitions of probable and possible reserves and contingent
resources imply different probabilities of potential recovery in each
classification; the quantities reported here are unrisked and based on
the company’s estimate of current costs to drill wells in each basin and
bring associated production to market. [See Cautionary Statements on p.
9].
Hedges
Energen entered 2018 with 13.5 mmbo, or 65 percent of its estimated
production guidance midpoint, hedged with 3-way collars at an average
call price of $60.04 per barrel. Approximately 38 percent of its
estimated NGL volumes has been hedged an average price of $0.59 per
gallon; and some 8 percent of its gas volumes has been hedged at an
average NYMEX-equivalent price of $3.56 per Mcf.
Energen also has hedged the WTI Midland to WTI Cushing differential for
10.8 million barrels, or 58 percent of its estimated sweet oil
production, at an average price of $(1.01) per barrel.
2018 Hedges
|
|
|
|
|
|
|
Oil
|
|
2018 Hedge Volumes
|
|
% Hedged
|
|
Avg. NYMEX Price
|
Three-way Collars
|
|
13.5 mmbo
|
|
65%
|
|
|
Call Price
|
|
|
|
|
|
$ 60.04 per barrel
|
Put Price
|
|
|
|
|
|
$ 45.47 per barrel
|
Short Put Price
|
|
|
|
|
|
$ 35.47 per barrel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
2018 Hedge Volumes
|
|
% Hedged
|
|
Avg. NYMEXe Price
|
NGL
|
|
105.8 mm gallons
|
|
38%
|
|
$ 0.59 per gallon
|
Natural Gas
|
|
3.6 bcf
|
|
8%
|
|
$ 3.56 per mcf
|
|
|
|
|
|
|
|
Energen’s average realized prices in 2018 will reflect commodity and
basis hedges, oil transportation charges of approximately $1.95 per
barrel, NGL T&F fees of approximately $0.14 per gallon, and basis
differentials applicable to unhedged production. Gas and NGL production
also are subject to percent of proceeds contracts of approximately 85%.
The assumed natural gas basis for 2018 is $(1.00) per Mcf, and the
assumed WTI Midland to WTI Cushing basis differential is $(1.15).
Assumed prices for unhedged volumes in 2018 are $58/barrel,
$0.65/gallon, and $2.75 per Mcf.
All 2018 hedges are pro rata throughout the year.
Estimated Price Realizations (pre-hedge):
|
|
|
|
|
|
|
CY18e
|
|
1Q18e
|
Crude oil (% of NYMEX/WTI)
|
|
95
|
%
|
|
96
|
%
|
NGL (after T&F) (% of NYMEX/WTI)
|
|
32
|
%
|
|
33
|
%
|
Natural gas (% of NYMEX/Henry Hub)
|
|
52
|
%
|
|
59
|
%
|
|
|
|
|
|
2019 Hedges
|
|
|
|
|
Oil
|
|
2019 Hedge Volumes
|
|
Avg. NYMEX Price
|
Three-way Collars
|
|
5.4 mmbo
|
|
|
Call Price
|
|
|
|
$ 61.53 per barrel
|
Put Price
|
|
|
|
$ 45.67 per barrel
|
Short Put Price
|
|
|
|
$ 35.67 per barrel
|
|
|
|
|
|
In addition, Energen has hedges in place for 25.2 million gallons of
2019 NGL production at an average price of $0.66 per gallon and has
hedged the Midland to Cushing differential on approximately 5.0 million
barrels of its 2019 oil production at an average price of $(0.44).
Conference Call
4Q17 slides associated with Energen’s quarterly release and conference
call are available at www.energen.com.
Energen will hold its quarterly conference call Tuesday, February 20, at
8:30 a.m. ET. Investment community members may participate by calling
1-877-407-8289 (reference Energen earnings call). A live audio Webcast
of the program as well as a replay may be accessed via www.energen.com.
Energen Corporation is an oil-focused exploration and production
company with operations in the Permian Basin in west Texas and New
Mexico. For more information, go to www.energen.com.
FORWARD LOOKING STATEMENTS: All statements, other than statements
of historical fact, appearing in this release constitute forward-looking
statements within the meaning of the Private Securities Litigation
Reform Act of 1995. These forward-looking statements include, among
other things, statements about our expectations, beliefs, intentions or
business strategies for the future, statements concerning our outlook
with regard to the timing and amount of future production of oil,
natural gas liquids and natural gas, price realizations, the nature and
timing of capital expenditures for exploration and development, plans
for funding operations and drilling program capital expenditures, the
timing and success of specific projects, operating costs and other
expenses, proved oil and natural gas reserves, liquidity and capital
resources, outcomes and effects of litigation, claims and disputes and
derivative activities. Forward-looking statements may include words such
as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”,
“foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”,
“seek”, “will” or other words or expressions concerning matters that are
not historical facts. These statements involve certain risks and
uncertainties that may cause actual results to differ materially from
expectations as of the date of this news release. Except as otherwise
disclosed, the forward-looking statements do not reflect the impact of
possible or pending acquisitions, investments, divestitures or
restructurings. The absence of errors in input data, calculations and
formulas used in estimates, assumptions and forecasts cannot be
guaranteed. We base our forward-looking statements on information
currently available to us, and we undertake no obligation to correct or
update these statements whether as a result of new information, future
events or otherwise. Additional information regarding our
forward‐looking statements and related risks and uncertainties that
could affect future results of Energen, can be found in the Company’s
periodic reports filed with the Securities and Exchange Commission and
available on the Company’s website - www.energen.com.
CAUTIONARY STATEMENTS: The SEC permits oil and gas companies to
disclose in SEC filings only proved, probable and possible reserves that
meet the SEC’s definitions for such terms, and price and cost
sensitivities for such reserves, and prohibits disclosure of resources
that do not constitute such reserves. Outside of SEC filings, we use the
terms “estimated ultimate recovery” or “EUR,” reserve or resource
“potential,” “contingent resources” and other descriptions of volumes of
non-proved reserves or resources potentially recoverable through
additional drilling or recovery techniques. These estimates are
inherently more speculative than estimates of proved reserves and are
subject to substantially greater risk of actually being realized. We
have not risked EUR estimates, potential drilling locations, and
resource potential estimates. Actual locations drilled and quantities
that may be ultimately recovered may differ substantially from
estimates. We make no commitment to drill all of the drilling locations
that have been attributed these quantities. Factors affecting ultimate
recovery include the scope of our on-going drilling program, which will
be directly affected by the availability of capital, drilling, and
production costs, availability of drilling and completion services and
equipment, drilling results, lease expirations, regulatory approvals,
and geological and mechanical factors. Estimates of unproved reserves,
type/decline curves, per-well EURs, and resource potential may change
significantly as development of our oil and gas assets provides
additional data. Additionally, initial production rates contained in
this news release are subject to decline over time and should not be
regarded as reflective of sustained production levels.
Financial, operating, and support data pertaining to all reporting
periods included in this release are unaudited and subject to revision.
|
Non-GAAP Financial Measures
|
|
Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to
generally accepted accounting principles) which excludes the effects
of certain non-cash mark-to-market derivative financial instruments.
Adjusted income from continuing operations further excludes
impairment losses, income (loss) associated with divestitures, and
the benefit of the Tax Cut and Jobs Act. Energen believes that
excluding the impact of these items is more useful to analysts and
investors in comparing the results of operations and operational
trends between reporting periods and relative to other oil and gas
producing companies.
|
|
|
|
|
|
|
Three Months Ended 12/31/17
|
Energen Net Income ($ in millions except per share data)
|
|
Net Income
|
|
Per Diluted
Share
|
Net Income (Loss) All Operations (GAAP)
|
|
262.4
|
|
|
|
2.68
|
|
Non-cash mark-to-market losses (net of $20.6 tax)
|
|
37.5
|
|
|
|
0.38
|
|
Asset impairment, other (net of $0.8 tax)
|
|
1.4
|
|
|
|
0.01
|
|
Benefit of Tax Cuts and Jobs Act
|
|
(240.1
|
)
|
|
|
(2.45
|
)
|
Adjusted Income from Continuing Operations (Non-GAAP)
|
|
61.3
|
|
|
|
0.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended 12/31/16
|
Energen Net Income ($ in millions except per share data)
|
|
Net Income
|
|
Per Diluted
Share
|
Net Income (Loss) All Operations (GAAP)
|
|
(54.5
|
)
|
|
|
(0.56
|
)
|
Non-cash mark-to-market losses (net of $12.5 tax)
|
|
22.8
|
|
|
|
0.23
|
|
Asset impairment, other (net of $0.0 tax) *
|
|
nm
|
|
|
nm
|
Loss associated with property sales (net of $1.3 tax)
|
|
5.0
|
|
|
|
0.05
|
|
Adjusted Income from Continuing Operations (Non-GAAP)
|
|
(26.6
|
)
|
|
|
(0.27
|
)
|
|
|
|
|
|
|
Note: Amounts may not sum due to rounding
|
|
|
|
|
|
|
*Approximately $25,000 (net of tax)
|
|
|
|
|
|
|
|
Non-GAAP Financial Measures
|
|
Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to
generally accepted accounting principles) which excludes the effects
of certain non-cash mark-to-market derivative financial instruments.
Adjusted income from continuing operations further excludes
impairment losses, certain prior period losses associated with a
reduction in force, pension settlement expenses, income associated
with divestitures, and the benefit of the Tax Cut and Jobs Act.
Energen believes that excluding the impact of these items is more
useful to analysts and investors in comparing the results of
operations and operational trends between reporting periods and
relative to other oil and gas producing companies.
|
|
|
|
|
|
|
|
|
|
Year Ended 12/31/17
|
|
Energen Net Income ($ in millions except per share data)
|
|
Net Income
|
|
Per Diluted
Share
|
|
Net Income (Loss) All Operations (GAAP)
|
|
306.8
|
|
|
3.14
|
|
|
Non-cash mark-to-market losses (net of $3.8 tax)
|
|
6.9
|
|
|
0.07
|
|
|
Asset impairment, other (net of $1.4 tax)
|
|
2.4
|
|
|
0.03
|
|
|
Income associated with property sales (net of $2.0 tax)
|
|
(2.5
|
)
|
|
(0.03
|
)
|
|
Benefit of Tax Cuts and Jobs Act
|
|
(240.1
|
)
|
|
(2.46
|
)
|
|
Adjusted Income from Continuing Operations (Non-GAAP)
|
|
73.6
|
|
|
0.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended 12/31/16
|
|
Energen Net Income ($ in millions except per share data)
|
|
Net Income
|
|
Per Diluted
Share
|
|
Net Income (Loss) All Operations (GAAP)
|
|
(167.5
|
)
|
|
(1.77
|
)
|
|
Non-cash mark-to-market losses (net of $25.3 tax)
|
|
45.9
|
|
|
0.49
|
|
|
Asset impairment, other (net of $67.5 tax)
|
|
121.7
|
|
|
1.29
|
|
|
Income associated with property sales (net of $76.1 tax)
|
|
(134.6
|
)
|
|
(1.42
|
)
|
|
Pension settlement expenses (net of $1.2 tax)
|
|
2.2
|
|
|
0.02
|
|
|
Reduction in force expenses (net of $1.9 tax)
|
|
3.5
|
|
|
0.04
|
|
|
Adjusted Income from Continuing Operations (Non-GAAP)
|
|
(128.8
|
)
|
|
(1.36
|
)
|
|
|
|
|
|
|
|
Note: Amounts may not sum due to rounding
|
|
|
|
|
|
|
|
Non-GAAP Financial Measures
|
|
Earnings before interest, taxes, depreciation, depletion,
amortization and exploration expenses (EBITDAX) is a Non-GAAP
financial measure (GAAP refers to generally accepted accounting
principles). Adjusted EBITDAX from continuing operations further
excludes impairment losses, certain non-cash mark-to-market
derivative financial instruments, and income (loss) associated with
divestitures. Energen believes these measures allow analysts and
investors to understand the financial performance of the company
from core business operations, without including the effects of
capital structure, tax rates and depreciation. Further, this measure
is useful in comparing the company and other oil and gas producing
companies.
|
|
|
|
|
Reconciliation To GAAP Information
|
|
Three Months Ended 12/31
|
($ in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
Energen Net Income (Loss) (GAAP)
|
|
262.4
|
|
|
(54.5
|
)
|
Loss associated with property sales, net of tax
|
|
0.0
|
|
|
5.0
|
|
Net Income (Loss) Excluding Property Sales (Non-GAAP)
|
|
262.4
|
|
|
(49.5
|
)
|
Interest expense
|
|
10.3
|
|
|
9.0
|
|
Income tax expense (benefit) **
|
|
(225.8
|
)
|
|
(21.5
|
)
|
Depreciation, depletion and amortization
|
|
130.4
|
|
|
103.4
|
|
Accretion expense
|
|
1.5
|
|
|
1.6
|
|
Exploration expense
|
|
1.7
|
|
|
3.6
|
|
Adjustment for asset impairment
|
|
2.2
|
|
|
nm
|
Adjustment for mark-to-market (gains)/ losses
|
|
58.2
|
|
|
35.3
|
|
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)
|
|
241.0
|
|
|
82.1
|
|
|
|
|
|
|
Note: Amounts may not sum due to rounding
|
|
|
|
|
|
** Amount adjusted to exclude 2016 property sales in prior
period. See reconciliation to GAAP Information for the Three
Months Ended 12/31/2016.
|
|
|
|
|
|
|
Non-GAAP Financial Measures
|
|
Earnings before interest, taxes, depreciation, depletion,
amortization and exploration expenses (EBITDAX) is a Non-GAAP
financial measure (GAAP refers to generally accepted accounting
principles). Adjusted EBITDAX from continuing operations further
excludes impairment losses, certain non-cash mark-to-market
derivative financial instruments, prior period losses associated
with a reduction in force, pension settlement expenses, and income
associated with divestitures. Energen believes these measures allow
analysts and investors to understand the financial performance of
the company from core business operations, without including the
effects of capital structure, tax rates and depreciation. Further,
this measure is useful in comparing the company and other oil and
gas producing companies.
|
|
|
|
|
Reconciliation To GAAP Information
|
|
Year Ended 12/31
|
($ in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
Energen Net Income (Loss) (GAAP)
|
|
306.8
|
|
|
(167.5
|
)
|
Income associated with property sales, net of tax*
|
|
(2.5
|
)
|
|
(134.6
|
)
|
Net Income (Loss) Excluding Property Sales (Non-GAAP)
|
|
304.3
|
|
|
(302.1
|
)
|
Interest expense
|
|
38.4
|
|
|
36.9
|
|
Income tax expense (benefit) **
|
|
(201.4
|
)
|
|
(155.7
|
)
|
Depreciation, depletion and amortization **
|
|
483.4
|
|
|
433.4
|
|
Accretion expense **
|
|
5.8
|
|
|
6.2
|
|
Exploration expense **
|
|
7.9
|
|
|
5.3
|
|
Adjustment for asset impairment
|
|
3.8
|
|
|
189.2
|
|
Adjustment for mark-to-market (gains)/ losses
|
|
10.8
|
|
|
71.2
|
|
Adjustment for pension settlement expenses
|
|
0.0
|
|
|
3.3
|
|
Adjustment for reduction in force expenses
|
|
0.0
|
|
|
5.5
|
|
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)
|
|
653.0
|
|
|
293.2
|
|
|
|
|
|
|
Note: Amounts may not sum due to rounding
|
|
|
|
|
|
*For quarter to quarter comparability, excluded from GAAP
income in the current quarter is an immaterial sale of certain
unproved leasehold properties in Wyoming.
|
|
|
|
|
|
** Amount adjusted to exclude 2016 property sales in prior
period. See reconciliation to GAAP Information for the Year Ended
12/31/2016.
|
|
|
|
|
|
|
Non-GAAP Financial Measures
|
|
The consolidated statement of income excluding certain divestments
is a Non-GAAP financial measure (GAAP refers to generally accepted
accounting principles). Energen believes excluding information
associated with 2016 property sales provides analysts and investors
useful information to understand the financial performance of the
company from ongoing business operations. Further, this information
is useful in comparing the company and other oil and gas producing
companies operating primarily in the Permian Basin.
|
|
|
|
|
|
|
|
|
Energen Net Income (Loss) Excluding 2016 Property Sales
|
|
|
|
|
|
|
Reconciliation to GAAP Information
|
|
Three Months Ended
|
|
|
December 31, 2016
|
(in thousands except per share and production data)
|
|
|
|
|
|
|
|
|
GAAP
|
|
2016 Property Sales
|
|
Non-GAAP
|
Revenues
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas sales
|
|
$
|
162,992
|
|
|
$
|
42
|
|
|
$
|
162,950
|
|
Gain (loss) on derivative instruments
|
|
|
(48,472
|
)
|
|
|
-
|
|
|
|
(48,472
|
)
|
Total Revenues
|
|
|
114,520
|
|
|
|
42
|
|
|
|
114,478
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production
|
|
|
38,867
|
|
|
|
258
|
|
|
|
38,609
|
|
Production and ad valorem taxes
|
|
|
9,516
|
|
|
|
209
|
|
|
|
9,307
|
|
O&G Depreciation, depletion and amortization
|
|
|
102,230
|
|
|
|
-
|
|
|
|
102,230
|
|
FF&E Depreciation, depletion and amortization
|
|
|
1,167
|
|
|
|
-
|
|
|
|
1,167
|
|
Asset impairment
|
|
|
40
|
|
|
|
-
|
|
|
|
40
|
|
Exploration
|
|
|
3,635
|
|
|
|
-
|
|
|
|
3,635
|
|
General and administrative
|
|
|
20,906
|
|
|
|
1
|
|
|
|
20,905
|
|
Accretion of discount on asset retirement obligations
|
|
|
1,580
|
|
|
|
-
|
|
|
|
1,580
|
|
(Gain) loss on sale of assets and other
|
|
|
5,175
|
|
|
|
5,889
|
|
|
|
(714
|
)
|
Total costs and expenses
|
|
|
183,116
|
|
|
|
6,357
|
|
|
|
176,759
|
|
Operating Income (Loss)
|
|
|
(68,596
|
)
|
|
|
(6,315
|
)
|
|
|
(62,281
|
)
|
Other Income/(Expense)
|
|
|
|
|
|
|
Interest expense
|
|
|
(9,041
|
)
|
|
|
-
|
|
|
|
(9,041
|
)
|
Other income
|
|
|
398
|
|
|
|
8
|
|
|
|
390
|
|
Total other expense
|
|
|
(8,643
|
)
|
|
|
8
|
|
|
|
(8,651
|
)
|
|
|
|
|
|
|
|
Loss Before Income Taxes
|
|
|
(77,239
|
)
|
|
|
(6,307
|
)
|
|
|
(70,932
|
)
|
Income tax expense (benefit)
|
|
|
(22,769
|
)
|
|
|
(1,293
|
)
|
|
|
(21,476
|
)
|
Net Income (Loss)
|
|
$
|
(54,470
|
)
|
|
$
|
(5,014
|
)
|
|
$
|
(49,456
|
)
|
|
|
|
|
|
|
|
Diluted Earnings Per Average Common Share
|
|
$
|
(0.56
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(0.51
|
)
|
|
|
|
|
|
|
|
Basic earning Per Average Common Share
|
|
$
|
(0.56
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(0.51
|
)
|
|
|
|
|
|
|
|
Oil
|
|
|
2,944
|
|
|
|
1
|
|
|
|
2,943
|
|
NGL
|
|
|
892
|
|
|
|
1
|
|
|
|
891
|
|
Natural Gas
|
|
|
1,084
|
|
|
|
-
|
|
|
|
1,084
|
|
Total Production (mboe)
|
|
|
4,920
|
|
|
|
2
|
|
|
|
4,918
|
|
Total Production (boepd)
|
|
|
53,478
|
|
|
|
22
|
|
|
|
53,457
|
|
|
|
|
|
|
|
|
Note: Amounts may not sum due to rounding
|
|
|
|
|
|
|
|
|
Non-GAAP Financial Measures
|
|
The consolidated statement of income excluding certain divestments
is a Non-GAAP financial measure (GAAP refers to generally accepted
accounting principles). Energen believes excluding information
associated with 2016 property sales provides analysts and investors
useful information to understand the financial performance of the
company from ongoing business operations. Further, this information
is useful in comparing the company and other oil and gas producing
companies operating primarily in the Permian Basin.
|
|
|
|
|
|
|
|
|
Energen Net Income (Loss) Excluding 2016 Property Sales
|
|
|
|
|
|
|
Reconciliation to GAAP Information
|
|
Year Ended
|
|
|
December 31, 2016
|
(in thousands except per share and production data)
|
|
|
|
|
|
|
|
|
GAAP
|
|
2016 Property Sales
|
|
Non-GAAP
|
Revenues
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas sales
|
|
$
|
621,366
|
|
|
$
|
29,808
|
|
|
$
|
591,558
|
|
Gain (loss) on derivative instruments
|
|
|
(88,477
|
)
|
|
|
-
|
|
|
|
(88,477
|
)
|
Total Revenues
|
|
|
532,889
|
|
|
|
29,808
|
|
|
|
503,081
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production
|
|
|
171,714
|
|
|
|
14,784
|
|
|
|
156,930
|
|
Production and ad valorem taxes
|
|
|
42,938
|
|
|
|
3,589
|
|
|
|
39,349
|
|
O&G Depreciation, depletion and amortization
|
|
|
443,007
|
|
|
|
14,366
|
|
|
|
428,641
|
|
FF&E Depreciation, depletion and amortization
|
|
|
4,954
|
|
|
|
153
|
|
|
|
4,801
|
|
Asset impairment
|
|
|
220,652
|
|
|
|
31,407
|
|
|
|
189,245
|
|
Exploration
|
|
|
5,415
|
|
|
|
117
|
|
|
|
5,298
|
|
General and administrative
|
|
|
95,689
|
|
|
|
523
|
|
|
|
95,166
|
|
Accretion of discount on asset retirement obligations
|
|
|
6,672
|
|
|
|
501
|
|
|
|
6,171
|
|
(Gain) loss on sale of assets and other
|
|
|
(246,922
|
)
|
|
|
(246,283
|
)
|
|
|
(639
|
)
|
Total costs and expenses
|
|
|
744,119
|
|
|
|
(180,843
|
)
|
|
|
924,962
|
|
Operating Income (Loss)
|
|
|
(211,230
|
)
|
|
|
210,651
|
|
|
|
(421,881
|
)
|
Other Income/(Expense)
|
|
|
|
|
|
|
Interest expense
|
|
|
(36,899
|
)
|
|
|
-
|
|
|
|
(36,899
|
)
|
Other income
|
|
|
978
|
|
|
|
58
|
|
|
|
920
|
|
Total other expense
|
|
|
(35,921
|
)
|
|
|
58
|
|
|
|
(35,979
|
)
|
|
|
|
|
|
|
|
Loss Before Income Taxes
|
|
|
(247,151
|
)
|
|
|
210,709
|
|
|
|
(457,860
|
)
|
Income tax expense (benefit)
|
|
|
(79,638
|
)
|
|
|
76,102
|
|
|
|
(155,740
|
)
|
Net Income (Loss)
|
|
$
|
(167,513
|
)
|
|
$
|
134,607
|
|
|
$
|
(302,120
|
)
|
|
|
|
|
|
|
|
Diluted Earnings Per Average Common Share
|
|
$
|
(1.77
|
)
|
|
$
|
1.43
|
|
|
$
|
(3.20
|
)
|
|
|
|
|
|
|
|
Basic earning Per Average Common Share
|
|
$
|
(1.77
|
)
|
|
$
|
1.43
|
|
|
$
|
(3.20
|
)
|
|
|
|
|
|
|
|
Oil
|
|
|
13,213
|
|
|
|
597
|
|
|
|
12,616
|
|
NGL
|
|
|
3,892
|
|
|
|
432
|
|
|
|
3,460
|
|
Natural Gas
|
|
|
4,534
|
|
|
|
629
|
|
|
|
3,905
|
|
Total Production (mboe)
|
|
|
21,639
|
|
|
|
1,658
|
|
|
|
19,981
|
|
Total Production (boepd)
|
|
|
59,123
|
|
|
|
4,530
|
|
|
|
54,593
|
|
|
|
|
|
|
|
|
Note: Amounts may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
|
For the 3 months ending December 31, 2017 and 2016
|
|
|
|
|
|
|
|
|
4th Quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share data)
|
|
2017
|
|
2016
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas sales
|
|
$
|
343,226
|
|
|
$
|
162,992
|
|
|
$
|
180,234
|
|
Loss on derivative instruments, net
|
|
|
(71,430
|
)
|
|
|
(48,472
|
)
|
|
|
(22,958
|
)
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
271,796
|
|
|
|
114,520
|
|
|
|
157,276
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production
|
|
|
53,951
|
|
|
|
38,867
|
|
|
|
15,084
|
|
Production and ad valorem taxes
|
|
|
18,083
|
|
|
|
9,516
|
|
|
|
8,567
|
|
Depreciation, depletion and amortization
|
|
|
130,419
|
|
|
|
103,397
|
|
|
|
27,022
|
|
Asset impairment
|
|
|
82
|
|
|
|
40
|
|
|
|
42
|
|
Exploration
|
|
|
3,816
|
|
|
|
3,635
|
|
|
|
181
|
|
General and administrative (including stock-based compensation
of $4,301 and $5,148 for the three months ended December 31, 2017,
and 2016, respectively)
|
|
|
23,158
|
|
|
|
20,906
|
|
|
|
2,252
|
|
Accretion of discount on asset retirement obligations
|
|
|
1,501
|
|
|
|
1,580
|
|
|
|
(79
|
)
|
(Gain) loss on sale of assets and other, net
|
|
|
(6,031
|
)
|
|
|
5,175
|
|
|
|
(11,206
|
)
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
224,979
|
|
|
|
183,116
|
|
|
|
41,863
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
46,817
|
|
|
|
(68,596
|
)
|
|
|
115,413
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(10,327
|
)
|
|
|
(9,041
|
)
|
|
|
(1,286
|
)
|
Other income
|
|
|
131
|
|
|
|
398
|
|
|
|
(267
|
)
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(10,196
|
)
|
|
|
(8,643
|
)
|
|
|
(1,553
|
)
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
|
|
36,621
|
|
|
|
(77,239
|
)
|
|
|
113,860
|
|
Income tax benefit
|
|
|
(225,809
|
)
|
|
|
(22,769
|
)
|
|
|
(203,040
|
)
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
262,430
|
|
|
$
|
(54,470
|
)
|
|
$
|
316,900
|
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Average Common Share
|
|
$
|
2.68
|
|
|
$
|
(0.56
|
)
|
|
$
|
3.24
|
|
Basic Earnings Per Average Common Share
|
|
$
|
2.70
|
|
|
$
|
(0.56
|
)
|
|
$
|
3.26
|
|
Diluted Average Common Shares Outstanding
|
|
|
97,831
|
|
|
|
97,074
|
|
|
|
757
|
|
Basic Average Common Shares Outstanding
|
|
|
97,202
|
|
|
|
97,074
|
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
|
For the 12 months ending December 31, 2017 and 2016
|
|
|
|
|
|
|
|
|
Year-to-date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share data)
|
|
2017
|
|
2016
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas sales
|
|
$
|
987,438
|
|
|
$
|
621,366
|
|
|
$
|
366,072
|
|
Loss on derivative instruments, net
|
|
|
(26,393
|
)
|
|
|
(88,477
|
)
|
|
|
62,084
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
961,045
|
|
|
|
532,889
|
|
|
|
428,156
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production
|
|
|
183,697
|
|
|
|
171,714
|
|
|
|
11,983
|
|
Production and ad valorem taxes
|
|
|
59,447
|
|
|
|
42,938
|
|
|
|
16,509
|
|
Depreciation, depletion and amortization
|
|
|
483,376
|
|
|
|
447,961
|
|
|
|
35,415
|
|
Asset impairment
|
|
|
1,671
|
|
|
|
220,652
|
|
|
|
(218,981
|
)
|
Exploration
|
|
|
10,075
|
|
|
|
5,415
|
|
|
|
4,660
|
|
General and administrative (including stock-based compensation of
$15,402 and $19,641 for the years ended December 31, 2017, and 2016,
respectively)
|
|
|
84,823
|
|
|
|
95,689
|
|
|
|
(10,866
|
)
|
Accretion of discount on asset retirement obligations
|
|
|
5,831
|
|
|
|
6,672
|
|
|
|
(841
|
)
|
Gain on sale of assets and other, net
|
|
|
(13,011
|
)
|
|
|
(246,922
|
)
|
|
|
233,911
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
815,909
|
|
|
|
744,119
|
|
|
|
71,790
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
145,136
|
|
|
|
(211,230
|
)
|
|
|
356,366
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(38,366
|
)
|
|
|
(36,899
|
)
|
|
|
(1,467
|
)
|
Other income
|
|
|
617
|
|
|
|
978
|
|
|
|
(361
|
)
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(37,749
|
)
|
|
|
(35,921
|
)
|
|
|
(1,828
|
)
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
|
|
107,387
|
|
|
|
(247,151
|
)
|
|
|
354,538
|
|
Income tax benefit
|
|
|
(199,441
|
)
|
|
|
(79,638
|
)
|
|
|
(119,803
|
)
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
306,828
|
|
|
$
|
(167,513
|
)
|
|
$
|
474,341
|
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Average Common Share
|
|
$
|
3.14
|
|
|
$
|
(1.77
|
)
|
|
$
|
4.91
|
|
Basic Earnings Per Average Common Share
|
|
$
|
3.16
|
|
|
$
|
(1.77
|
)
|
|
$
|
4.93
|
|
Diluted Average Common Shares Outstanding
|
|
|
97,707
|
|
|
|
94,476
|
|
|
|
3,231
|
|
Basic Average Common Shares Outstanding
|
|
|
97,182
|
|
|
|
94,476
|
|
|
|
2,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
As of December 31, 2017 and 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
December 31, 2017
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
439
|
|
$
|
386,093
|
Accounts receivable, net
|
|
|
158,787
|
|
|
73,322
|
Inventories, net
|
|
|
13,177
|
|
|
14,222
|
Derivative instruments
|
|
|
−
|
|
|
50
|
Income tax receivable
|
|
|
6,905
|
|
|
27,153
|
Prepayments and other
|
|
|
12,085
|
|
|
5,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
191,393
|
|
|
505,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
Oil and natural gas properties, net
|
|
|
4,718,939
|
|
|
4,016,683
|
Other property and equipment, net
|
|
|
44,581
|
|
|
44,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
|
4,763,520
|
|
|
4,061,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other postretirement assets
|
|
|
2,646
|
|
|
3,619
|
Noncurrent derivative instruments
|
|
|
70,716
|
|
|
−
|
Other assets
|
|
|
5,620
|
|
|
8,741
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
5,033,895
|
|
$
|
4,579,823
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
Long-term debt due within one year
|
|
$
|
−
|
|
$
|
24,000
|
Accounts payable
|
|
|
75,167
|
|
|
65,031
|
Accrued taxes
|
|
|
2,631
|
|
|
7,252
|
Accrued wages and benefits
|
|
|
26,170
|
|
|
25,089
|
Accrued capital costs
|
|
|
74,909
|
|
|
79,988
|
Revenue and royalty payable
|
|
|
54,072
|
|
|
51,217
|
Derivative instruments
|
|
|
71,379
|
|
|
65,467
|
Other
|
|
|
17,916
|
|
|
20,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
322,244
|
|
|
338,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
782,861
|
|
|
527,443
|
Asset retirement obligations
|
|
|
88,378
|
|
|
81,544
|
Noncurrent derivative instruments
|
|
|
8,886
|
|
|
3,006
|
Deferred income taxes
|
|
|
387,807
|
|
|
495,888
|
Other long-term liabilities
|
|
|
5,262
|
|
|
13,136
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
1,595,438
|
|
|
1,459,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Shareholders’ Equity
|
|
|
3,438,457
|
|
|
3,120,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
5,033,895
|
|
$
|
4,579,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
|
For the 3 months ending December 31, 2017 and 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4th Quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except sales price and per unit data)
|
|
2017
|
|
2016
|
|
Change
|
Operating and production data
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas sales
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
281,818
|
|
$
|
134,112
|
|
$
|
147,706
|
Natural gas liquids
|
|
|
38,522
|
|
|
14,068
|
|
|
24,454
|
Natural gas
|
|
|
22,886
|
|
|
14,812
|
|
|
8,074
|
Total
|
|
$
|
343,226
|
|
$
|
162,992
|
|
$
|
180,234
|
|
|
|
|
|
|
|
|
|
|
Open non-cash mark-to-market gains (losses) on derivative instruments
|
Oil
|
|
$
|
(53,388)
|
|
$
|
(23,704)
|
|
$
|
(29,684)
|
Natural gas liquids
|
|
|
(4,863)
|
|
|
(5,914)
|
|
|
1,051
|
Natural gas
|
|
|
54
|
|
|
(5,712)
|
|
|
5,766
|
Total
|
|
$
|
(58,197)
|
|
$
|
(35,330)
|
|
$
|
(22,867)
|
|
|
|
|
|
|
|
|
|
|
Closed gains (losses) on derivative instruments
|
Oil
|
|
$
|
(10,894)
|
|
$
|
(12,380)
|
|
$
|
1,486
|
Natural gas liquids
|
|
|
(4,312)
|
|
|
−
|
|
|
(4,312)
|
Natural gas
|
|
|
1,973
|
|
|
(762)
|
|
|
2,735
|
Total
|
|
$
|
(13,233)
|
|
$
|
(13,142)
|
|
$
|
(91)
|
Total revenues
|
|
$
|
271,796
|
|
$
|
114,520
|
|
$
|
157,276
|
|
|
|
|
|
|
|
|
|
|
Production volumes
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
5,343
|
|
|
2,944
|
|
|
2,399
|
Natural gas liquids (MMgal)
|
|
|
74.8
|
|
|
37.5
|
|
|
37.3
|
Natural gas (MMcf)
|
|
|
11,028
|
|
|
6,504
|
|
|
4,524
|
Total production volumes (MBOE)
|
|
|
8,961
|
|
|
4,920
|
|
|
4,041
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes
Oil (MBbl/d)
|
|
|
58.1
|
|
|
32.0
|
|
|
26.1
|
Natural gas liquids (MMgal/d)
|
|
|
0.8
|
|
|
0.4
|
|
|
0.4
|
Natural gas (MMcf/d)
|
|
|
119.9
|
|
|
70.7
|
|
|
49.2
|
Total average daily production volumes (MBOE/d)
|
|
|
97.4
|
|
|
53.5
|
|
|
43.9
|
|
|
|
|
|
|
|
|
|
|
Average realized prices excluding effects of open non-cash
mark-to-market derivative instruments
|
Oil (per barrel)
|
|
$
|
50.71
|
|
$
|
41.35
|
|
$
|
9.36
|
Natural gas liquids (per gallon)
|
|
$
|
0.46
|
|
$
|
0.38
|
|
$
|
0.08
|
Natural gas (per Mcf)
|
|
$
|
2.25
|
|
$
|
2.16
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
Average realized prices excluding effects of all derivative
instruments
|
Oil (per barrel)
|
|
$
|
52.75
|
|
$
|
45.55
|
|
$
|
7.20
|
Natural gas liquids (per gallon)
|
|
$
|
0.52
|
|
$
|
0.38
|
|
$
|
0.14
|
Natural gas (per Mcf)
|
|
$
|
2.08
|
|
$
|
2.28
|
|
$
|
(0.20)
|
|
|
|
|
|
|
|
|
|
|
Costs per BOE
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production expenses
|
|
$
|
6.02
|
|
$
|
7.90
|
|
$
|
(1.88)
|
Production and ad valorem taxes
|
|
$
|
2.02
|
|
$
|
1.93
|
|
$
|
0.09
|
Depreciation, depletion and amortization
|
|
$
|
14.55
|
|
$
|
21.02
|
|
$
|
(6.47)
|
Exploration expense
|
|
$
|
0.43
|
|
$
|
0.74
|
|
$
|
(0.31)
|
General and administrative
|
|
$
|
2.58
|
|
$
|
4.25
|
|
$
|
(1.67)
|
Capital expenditures (including acquisitions)
|
|
$
|
217,475
|
|
$
|
154,455
|
|
$
|
63,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
|
For the 12 months ending December 31, 2017 and 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-to-date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except sales price and per unit data)
|
|
2017
|
|
2016
|
|
Change
|
Operating and production data
|
Oil, natural gas liquids and natural gas sales
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
814,470
|
|
|
$
|
521,017
|
|
|
$
|
293,453
|
|
Natural gas liquids
|
|
|
98,298
|
|
|
|
48,652
|
|
|
|
49,646
|
|
Natural gas
|
|
|
74,670
|
|
|
|
51,697
|
|
|
|
22,973
|
|
Total
|
|
$
|
987,438
|
|
|
$
|
621,366
|
|
|
$
|
366,072
|
|
|
|
|
|
|
|
|
|
|
|
Open non-cash mark-to-market gains (losses) on derivative instruments
|
Oil
|
|
$
|
(10,658
|
)
|
|
$
|
(57,148
|
)
|
|
$
|
46,490
|
|
Natural gas liquids
|
|
|
(9,011
|
)
|
|
|
(6,868
|
)
|
|
|
(2,143
|
)
|
Natural gas
|
|
|
8,910
|
|
|
|
(7,174
|
)
|
|
|
16,084
|
|
Total
|
|
$
|
(10,759
|
)
|
|
$
|
(71,190
|
)
|
|
$
|
60,431
|
|
|
|
|
|
|
|
|
|
|
|
Closed gains (losses) on derivative instruments
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
(11,364
|
)
|
|
$
|
(17,701
|
)
|
|
$
|
6,337
|
|
Natural gas liquids
|
|
|
(7,780
|
)
|
|
|
−
|
|
|
|
(7,780
|
)
|
Natural gas
|
|
|
3,510
|
|
|
|
414
|
|
|
|
3,096
|
|
Total
|
|
$
|
(15,634
|
)
|
|
$
|
(17,287
|
)
|
|
$
|
1,653
|
|
Total revenues
|
|
$
|
961,045
|
|
|
$
|
532,889
|
|
|
$
|
428,156
|
|
|
|
|
|
|
|
|
|
|
|
Production volumes
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
16,951
|
|
|
|
13,213
|
|
|
|
3,738
|
|
Natural gas liquids (MMgal)
|
|
|
220.7
|
|
|
|
163.5
|
|
|
|
57.2
|
|
Natural gas (MMcf)
|
|
|
33,528
|
|
|
|
27,204
|
|
|
|
6,324
|
|
Total production volumes (MBOE)
|
27,794
|
|
|
|
21,639
|
|
|
|
6,155
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes
Oil (MBbl/d)
|
|
|
46.4
|
|
|
|
36.1
|
|
|
|
10.3
|
|
Natural gas liquids (MMgal/d)
|
|
|
0.6
|
|
|
|
0.4
|
|
|
|
0.2
|
|
Natural gas (MMcf/d)
|
|
|
91.9
|
|
|
|
74.3
|
|
|
|
17.6
|
|
Total average daily production volumes (MBOE/d)
|
|
|
76.1
|
|
|
|
59.1
|
|
|
|
17.0
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices excluding effects of open non-cash
mark-to-market derivative instruments
|
Oil (per barrel)
|
|
$
|
47.38
|
|
|
$
|
38.09
|
|
|
$
|
9.29
|
|
Natural gas liquids (per gallon)
|
|
$
|
0.41
|
|
|
$
|
0.30
|
|
|
$
|
0.11
|
|
Natural gas (per Mcf)
|
|
$
|
2.33
|
|
|
$
|
1.92
|
|
|
$
|
0.41
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices excluding effects of all derivative
instruments
|
Oil (per barrel)
|
|
$
|
48.05
|
|
|
$
|
39.43
|
|
|
$
|
8.62
|
|
Natural gas liquids (per gallon)
|
|
$
|
0.45
|
|
|
$
|
0.30
|
|
|
$
|
0.15
|
|
Natural gas (per Mcf)
|
|
$
|
2.23
|
|
|
$
|
1.90
|
|
|
$
|
0.33
|
|
|
|
|
|
|
|
|
|
|
|
Costs per BOE
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production expenses
|
|
$
|
6.61
|
|
|
$
|
7.94
|
|
|
$
|
(1.33
|
)
|
Production and ad valorem taxes
|
|
$
|
2.14
|
|
|
$
|
1.98
|
|
|
$
|
0.16
|
|
Depreciation, depletion and amortization
|
|
$
|
17.39
|
|
|
$
|
20.70
|
|
|
$
|
(3.31
|
)
|
Exploration expense
|
|
$
|
0.36
|
|
|
$
|
0.25
|
|
|
$
|
0.11
|
|
General and administrative
|
|
$
|
3.05
|
|
|
$
|
4.42
|
|
|
$
|
(1.37
|
)
|
Capital expenditures (includes acquisitions)
|
|
$
|
1,189,342
|
|
|
$
|
582,898
|
|
|
$
|
606,444
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20180220005582/en/ Copyright Business Wire 2018
Source: Business Wire
(February 20, 2018 - 6:00 AM EST)
News by QuoteMedia
www.quotemedia.com
|