Download Strong Results Generated by 9 Appraisal Wells

For Release: 4:30 p.m. EDT
Contacts: Julie S. Ryland
Thursday, August 6, 2015
205.326.8421
ENERGEN RAISES 2015 ANNUAL PRODUCTION GUIDANCE BY 500,000 BOE
Strong Results Generated by 9 Appraisal Wells in Delaware, Midland basins
Continued Efficiency Gains Reflected in Declining Days to Drill Development Wells
Highlights
• Record production in 2015 estimated to increase 19% from 2014, with oil estimated to be up 21%
• Average length of time to drill to total depth 7,500’ Wolfcamp A development wells in Glasscock Co. in 2Q15 dropped by
7 days to 14, as efficiency gains continued; the shortest drill time was 11 days from spud to TD
• East to west across the southern Delaware Basin, 6 new Wolfcamp appraisal wells generate encouraging results
• Oil production from Lower Spraberry wells in Martin, Howard, Midland counties suggests attractive return potential
• 2Q15 production totaled 63,800 boepd, exceeding guidance midpoint by 8%
• 2Q15 oil production grew 27% from same period last year
• 4Q15 production rate estimated to average almost 68,000 boepd
• Capital budget increased 10% for additional drilling, completions, and facilities in Midland Basin in 2nd half of 2015
• Energen to drill additional 22 gross (19 net) wells in Midland Basin in Second Half of 2015
• Drilling under way in Rio Arriba Co., NM, as Energen begins to assess Mancos oil potential on its San Juan Basin acreage
• 2Q15 Glasscock Co. development program wells generated peak 30-day average rates of more than 850 boepd
BIRMINGHAM, Alabama – For the 3 months ended June 30, 2015, Energen Corporation (NYSE: EGN)
reported a GAAP net loss from all operations of $111.6 million, or $(1.52) per diluted share. Excluding mark-tomarket derivatives losses, impairment losses and other non-cash items, and a purchase price adjustment from
the sale of the majority of the company’s San Juan Basin assets in March 2015, Energen’s adjusted income in
the 2
nd
quarter of 2015 totaled $7.7 million, or $0.10 per diluted share. This compares with adjusted income
from continuing operations in the 2nd quarter of 2014 of $26.0 million, or $0.36 per diluted share. The variance
between the periods largely is attributable to a 22 percent decline in realized oil and natural gas liquids (NGL)
prices and higher depreciation, depletion, and amortization expense (DD&A) associated with increased drilling
activity, partially offset by a 23 percent increase in production. [See “Non-GAAP Financial Measures”
beginning on pp 14 for more information and reconciliation.]
Energen’s adjusted EBITDAX totaled $180.3 million in the 2
nd
quarter of 2015, up 4 percent from adjusted
EBITDAX from continuing operations in the same period last year of $172.9 million. [See “Non-GAAP Financial
Measures” beginning on pp 14 for more information and reconciliation.]
1
The company’s adjusted 2
nd
quarter net income approximated internal expectations as increased production,
lower lease operating expenses (LOE), and lower production and ad valorem taxes were essentially offset by
increased depreciation expense, lower commodity prices, higher net general and administrative expense
(G&A), and the timing of geological and geophysical (G&G) exploration expenses.
Production in the 2
nd
quarter of 2015 exceeded the guidance range midpoint by 8 percent (approximately
4,635 boepd) largely due to the continued impact of accelerated completions in the first quarter on Delaware
Basin production, better-than-expected well performance from Wolfcamp and 3
rd
Bone Spring wells in the
Delaware Basin, and the timing of horizontal completions in the Midland Basin.
“E
nergen’s strong performance as a leading operator in the Permian Basin continued in the second
quarter,” said James McManus, Energen’s chairman and chief executive officer. “Our oil
production increased almost 8,400 barrels a day from the same period last year and 11 percent from the
1st quarter, and we now expect total production in 2015 to show 19 percent growth, year-over-year.
“We have continued to improve our drilling efficiency by driving down the number of days to drill to
total depth in our Glasscock County development program. We have continued to refine our completions
and are encouraged by the early production response we have seen in our latest Wolfcamp development
wells. Production from our Lower Spraberry shale appraisal wells in the northern Midland Basin
continues to suggest the potential for outstanding returns. And an excellent set of Wolfcamp results
across the Delaware Basin continues to build an encouraging body of data that supports the long-term
potential of this play.
“Energen is well capitalized and well positioned to navigate through this period of uncertain commodity
prices; but, as we look ahead to 2016, we plan to proceed at a pace of development and investment that
will maintain our balance sheet strength and financial flexibility,” McManus added. “We have
outstanding assets in the Midland and Delaware Basins that support a rich inventory of opportunities,
and we plan to develop those assets in a manner that supports value creation for our shareholders.”
2nd Quarter Financial Review
Excluding mark-to-market derivatives losses, impairment losses and other non-cash items, and a purchase
price adjustment from the sale of the majority of the company’s San Juan Basin assets in March 2015,
Energen’s adjusted income in the 2
nd
quarter of 2015 totaled $7.7 million, or $0.10 per diluted share. This
compares with adjusted income from continuing operations in the 2nd quarter of 2014 of $26.0 million, or $0.36
per diluted share. The variance between the periods largely is attributable to a 22 percent decline in realized oil
and NGL prices and higher DD&A expense associated with increased drilling activity partially offset by a 23
percent increase in production. [See “Non-GAAP Financial Measures” beginning on pp 14 for more information
and reconciliation.]
2
More than 75 percent of the after-tax asset impairments of $42.9 million is related to a write down of a field in
the Central Basin Platform that is in tertiary recovery ($33 million); another $3.0 million covers approximately
775 net acres in Reeves County (Enterprise area).
Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
[See “Non-GAAP Financial Measures” beginning on pp 14 for more information]
2Q15
$M
Net Income/(Loss) All Operations (GAAP)
$
2Q14
$/dil. sh.
(111,601)
$
(1.52)
$M
$
$/dil. sh.
(7,953)
$
(0.11)
Less: Non-cash Mark-to-Market gain/(loss)
(75,133)
(1.02)
(38,131)
(0.52)
Less: Asset Impairment, other
(42,878)
(0.58)
(1,630)
(0.02)
(1,249)
(0.02)
10,615
0.15
--
(4,799)
(0.07)
Less: Income Associated w/ San Juan Basin Divestment
Less: Discontinued Operations
--
Adj. Income Continuing Operations (Non-GAAP)
$
7,659
$
0.10
$
25,992
$
0.36
Note: Per share amounts may not sum due to rounding
Production from Continuing Operations (excludes production associated with San Juan divestiture)
Commodity
2Q15
Change
(MBOE)
2Q14
MBOE
boepd
Oil
3,595
39,505
2,830
31,099
27 %
NGL
1,060
11,648
898
9,868
18 %
732
8,133
45 %
Natural Gas
1,151
12,648
986
10,835
17 %
904 10,044
27 %
5,806
63,802
4,714
51,802
23 %
4,869 54,100
19 %
Total
MBOE
boepd
Change
(MBOE)
1Q15
MBOE
boepd
3,233 35,922
11 %
Note: Totals may not sum due to rounding
Production from Continuing Operations (excludes production associated with San Juan divestiture)
Area
2Q15
MBOE
Change
(MBOE)
2Q14
boepd
MBOE
boepd
MBOE
boepd
2,320
25,778
27 %
Midland Basin
2,957
32,495
1,755
19,286
Wolfcamp/Cline/Spraberry
1,751
19,242
384
4,220
1,293
14,367
35 %
Wolfberry
1,206
13,253
1,371
15,066
1,027
11,411
17 %
Delaware Basin
1,450
15,934
1,488
16,352
1,225
13,611
18 %
3 Bone Spring/Other
963
10,582
1,174
12,901
875
9,722
10 %
Wolfcamp
487
5,352
314
3,451
350
3,889
39 %
Central Basin Platform
918
10,088
1,060
11,648
(13)%
909
10,100
1%
Total Permian Basin
5,324
58,505
4,303
47,286
24 %
4,454
49,489
20 %
San Juan Basin/Other
482
5,297
411
4,516
17 %
415
4,611
16 %
5,806
63,802
4,714
51,802
23 %
4,869
54,100
19 %
rd
Total
68 %
Change
(MBOE)
1Q15
(3)%
Note: Totals may not sum due to rounding
3
Average Realized Sales Prices from Continuing Operations
Commodity
2Q15
2Q14
Change
Oil (per barrel)
$
67.86
$
83.65
(19) %
NGL (per gallon)
$
0.33
$
0.72
(54) %
Natural Gas (per Mcf)
$
3.77
$
2.92*
29 %
* Prior period hedges were left unallocated for current-year San Juan Basin divestiture; as reported last year,
the average realized sales price of natural gas in 2Q14 was $4.25 per Mcf.
Average Prices from Continuing Operations Before Effects of Hedges
Commodity
2Q15
2Q14
Change
Oil (per barrel)
$
52.47
$
92.75
(43) %
NGL (per gallon)
$
0.33
$
0.72
(54) %
Natural Gas (per Mcf)
$
2.24
$
3.92
(43) %
Expenses from Continuing Operations and Excluding San Juan Basin Assets sold March 31, 2015
(per BOE, except interest expense)
Expenses
2Q15
2Q14
Change
LOE*
$
8.90
$
10.54
(16) %
Production & ad valorem taxes
$
2.33
$
5.15
(55) %
DD&A
$
25.56
$
25.63
(0.3) %
Net G&A
$
$
7.25
(11) %
$
8.0
40 %
6.47†
Interest ($MM)
$ 11.2
* Production costs + workovers and repairs + marketing and transportation
† Excludes $0.19 per BOE for pension and pension settlement expenses
2nd Quarter Comparisons, 2015 vs 2014 (excluding San Juan Basin assets sold March 31, 2015)
•
The success of Energen’s Wolfcamp development program led to a 68 percent increase in Midland
rd
Basin production; combined with expected declines in the 3 Bone Spring play in the Delaware Basin
and the company’s legacy assets in the Central Basin Platform, Energen’s total Permian Basin
production increased 24 percent.
•
The company’s average realized oil price fell 19 percent, while the realized price of NGL dropped 54
percent. Excluding the impact of commodity and differential hedges, the average realized price of oil
would have been $52.47 per barrel.
•
LOE per unit declined 16 percent to $8.90 per barrel largely due to the timing of workover expense,
lower power costs, and increased production, partially offset by higher rental equipment and water
disposal costs. Per-unit production and ad valorem taxes declined 55 percent.
•
Per-unit DD&A expense was essentially unchanged.
•
Per-unit net G&A expense of $6.47 per BOE (excluding pension and pension settlement expenses)
declined 11 percent from the same period a year ago largely due to increased production.
•
Interest expense increased 40 percent largely due to a prior-year reclassification of certain interest
expense to discontinued operations.
4
Liquidity Update
On June 22, Energen closed on the sale of 5.7 million shares of common stock for net proceeds of $399
million. Energen initially used net proceeds to repay borrowings outstanding under its revolving credit facility.
As of June 30, 2015, Energen had borrowings of $133.0 million on its revolving credit facility, which has a $1.6
billion borrowing base, and cash/cash equivalents of $1.5 million, for total liquidity available of $1.47 billion.
Long-term debt at the end of June totaled $553.6 million.
Midland Basin Development Program Results
Development program wells drilled in 2Q15 (gross/net)
29/27
Development program wells completed in 2Q15 (gross/net)
Development program wells awaiting completion at end of 2Q15 (gross/net) (gross/net)
Development program wells awaiting completion at YE15e (gross/net)
19/19
44/42
46/42
In its 2-well, pad-drilling development program in Glasscock County, Energen tested eight Wolfcamp A and B
wells during the 2
nd
quarter of 2015. These wells generated average peak 24-hour IP rates (3-stream) of 1,076
boepd (83% oil) and peak 30-day average rates (3-stream) of 856 boepd (68% oil). These average rates were
substantially higher than the comparable rates for the larger group of 22 gross development wells tested in the
st
1 quarter and likely were positively impacted, at least in part, by an adjustment made to the company’s
completion design.
The 57 gross (56 net) wells tested since the program’s inception in 2014 have generated average peak 24hour IPs (3-stream) of 930 boepd (81% oil) and peak 30-day average rates (3-stream) of 742 boepd (74% oil).
A supplemental slide posted at www.energen.com shows that the average production from these wells -normalized to a 7,000’ lateral length – are tracking very closely to the company’s unrisked type curve
normalized to 7,000’.
Energen continued to achieve efficiency gains in its development drilling program in Glasscock County in the
second quarter. For example, the average days to drill to total depth a Wolfcamp A well with a 7,500’ lateral
declined by approximately 7 days -- from 21 to 14 -- and the drill & complete cost of that same Wolfcamp A
well is now averaging at the company’s year-end target of $5.9 million. The shortest drill time during the
quarter was 11 days from spud to TD.
In a separate down-spacing test in Glasscock County, the company is in the early stages of analyzing initial
production results of 20 gross (20 net) Wolfcamp A and B wells with 4,400’ lateral lengths, half of which were
drilled on 660’ spacing and half on 440’ spacing. A multi-year analysis is expected in order to understand the
long-term implications of the tighter spacing concept. Nine wells were part of the 2014 program; the 11 in the
2015 program are among the wells completed in the 2
nd
quarter.
5
Energen’s total 2015 Midland Basin development program calls for the drilling of 100 gross (94 net) wells in
Glasscock and Martin counties, with 37 gross (33 net) wells remaining to be drilled in the second half of the
year. The company currently expects 46 gross (42 net) wells in the 2015 program to be completed in 2016.
Midland and Delaware Basin Appraisal Program Results
Energen tested nine new appraisal wells in the Permian Basin during the 2nd quarter of 2015, including its first
Lower Spraberry wells in Howard and Midland counties in the Midland Basin. [See locator maps
at www.energen.com]
Midland Basin (3-Stream Results)
Lateral length (ft) Frac
Peak 24-Hour IP
Peak 30-day Avg.
Drilled* Completed Stages Boepd %Oil %NGL %Gas Boepd %Oil %NGL %Gas
Well Name
Zone/
County
Smith SN 48-37 #501H
LSB/Howard
7,472
6,848
32
1,067
78
14
7
895
79
14
7
L.B. Epley NS 39-46 #501H
LSB/Midland
6,799
6,077
29
652
82
10
8
428
76
14
11
L.B. Epley NS 39-46 #201H WCB/Midland 6,848
6,293
* Represents distance from vertical departure to toe
30
1,053
74
14
12
885
76
13
11
Note: Totals may not foot due to rounding
The Smith SN 48-37 #501H, a Lower Spraberry well in Howard County, generated an excellent peak 24-hour
IP rate of 1,067 boepd (78% oil); the well’s peak 30-day average remained strong at 895 boepd (79% oil).
Through 81 days, the Smith well’s oil production is tracking very close to a 1.2 MMBOE EUR type curve. [See
cumulative oil performance over time and potential economics of the company’s four northern Midland
Basin Lower Spraberry wells at www.energen.com]
Further south in northern Midland County, in the heart of a vertical Spraberry field that dates back to the
1960s, the L.B. Epley NS 39-46 #501H showed the effects of that prior drilling. The well’s peak 24-hour IP rate
was 652 (82% oil), and its peak 30-day average was 428 boepd (76% oil). Even though this Lower Spraberry
Epley well is not as strong a performer as the company’s other northern Midland Basin Lower Spraberry wells,
its cumulative oil production through 52 days is tracking close to a 770 MBOE EUR type curve. Energen
estimates that its exposure in the Midland Basin to areas of Spraberry depletion associated with older vertical
drilling is limited to a maximum of 5,000 net acres in this area and that the vast majority of its Spraberry
potential is in areas with younger or fewer vertical wells.
A Wolfcamp B well drilled at the same location – the L.B. Epley NS 39-46 #201H ̶ generated an excellent 24-
hour IP rate of 1,053 (74% oil) and a peak 30-day average rate of 885 boepd (76% oil).
Energen plans to drill a total of 8 gross (8 net) Wolfcamp shale wells in its Midland Basin appraisal program in
2015. In addition to the two 2015 Wolfcamp wells for which results have been disclosed, three wells in
Glasscock County with 10,000’ laterals currently are flowing back; a fourth well is awaiting completion, another
is drilling, and the final well has not yet been spud.
6
Energen also plans to drill a total of 12 gross (12 net) Spraberry wells in its Midland Basin appraisal program in
2015; this reflects an additional 5 gross (5 net) wells now planned in the second half of 2015. In addition to
three Lower Spraberry wells in the 2015 program for which results have been disclosed, one well currently is
flowing back, four more wells are awaiting completion or are in various stages of completion, and the other
four wells have not yet been spud. All 20 gross (20 net) wells in Energen’s 2015 Midland Basin appraisal
program are expected to be completed by year-end 2015.
Delaware Basin (3-Stream Results)
Lateral length (ft) Frac
Peak 24-Hour IP
Peak 30-day Avg.
Stages
Drilled* Completed
Boepd %Oil %NGL %Gas Boepd %Oil %NGL %Gas
Well Name
Zone/
County
Helbing 56-5 #1H
WCB/Reeves
5,299
4,828
18
1,381
31
31
38
1,163
33
30
37
Helbing 56-6 #1H
WCB/Reeves
5,307
4,423
17
1,123
39
27
34
753
29
32
39
Jaymac 56-7 #1H
WCB/Reeves
4,781
4,163
16
1,167
33
30
37
888
34
30
37
Spectre State 54-4 #1H
WCB/Reeves
4,907
4,372
16
885
63
15
22
733
63
15
22
Piper State 54-14 #1H
WCA/Reeves
4,835
4,223
17
1,498
56
18
26
973
55
19
26
University 24-17 #1H
WCB/Ward
7,463
6,987
* Represents distance from vertical departure to toe
32
1,073
74
12
14
987
71
13
16
Note: Totals may not foot due to rounding
In the Delaware Basin, the Helbing 56-5 #1H and 56-6 #1H and the Jaymac 56-7 #1H were drilled into the Bbench of the Wolfcamp shale in western Reeves County and generated strong peak 24-hour IP rates of 1,381
boepd (31% oil), 1,123 boepd (39% oil), and 1,167 boepd (33% oil), respectively. Their peak 30-day average
rates were 1,163 boepd (33% oil), 753 boepd (29% oil), and 888 (34% oil), respectively.
In the central part of the Delaware Basin, the Piper State 54-14 #1H ̶ an A-bench well – had an impressive
peak 24-hour IP of 1,498 (56% oil) and a peak 30-day average of 973 boepd (55% oil). The Spectre State 54-4
#1H, a B-bench well, also was drilled in the central part of the basin and had a solid peak 24-hour IP of 885
boepd (63% oil) and a peak 30-day average of 733 boepd (63% oil). The Spectre State’s test rates were
limited due to water-handling constraints.
On the Eastern side of the Delaware Basin in Ward County, the company drilled the University 24-17 #1H into
the Wolfcamp B with a completed lateral length of approximately 7,000 feet. The results were very solid, with a
peak 24-hour IP of 1,073 (74% oil) and peak 30-day average of 987 boepd (71% oil). These test rates were
limited due to water-handling constraints. The company believes its successful execution of this longer lateral
in the Delaware Basin can be applied elsewhere in the basin.
Energen’s 2015 appraisal drilling program in the Delaware Basin totals 8 gross (8 net) Wolfcamp shale wells.
Results of 7 of these wells have been disclosed. The remaining well in the 2015 program is targeting the
Wolfcamp A in Winkler County and currently is being completed.
7
San Juan Basin Mancos Appraisal Program
Energen currently is drilling its first Mancos oil formation appraisal well in the San Juan Basin in Rio Arriba
County, NM. The company plans to drill 8 gross (8 net) wells in the second half of 2015 to test its 91,000 net
acres for Mancos oil potential. The company also is participating as a 50 percent non-operated participant in 6
gross (3 net) wells drilled by WPX Energy. The peak 24-hour and peak 30-day average oil production rates
only of these six wells averaged an attractive 923 barrels of oil per day and 479 barrels of oil per day,
respectively.
Capital, Production, and Financial Guidance
Energen increased its 2015 capital budget slightly to $1.1 billion. Drilling plans for 2015 now include an
additional 14 gross (11 net) Wolfcamp development wells, 3 gross (3 net) additional Spraberry development
wells, and 5 gross (5 net) additional Spraberry appraisal wells in the program. In addition, the company plans
to complete 6 gross (5 net) development wells previously scheduled for 2016 as well as the 5 new Spraberry
appraisal wells. The revised budget also reflects a net addition of approximately $14 million for infrastructure in
the Midland Basin needed to support 2016 drilling activity as well as approximately $10 million for additional
unproved leasehold in the Midland Basin.
Energen’s revised budget is based on running four horizontal drilling rigs in its Midland Basin development
program in the last six months of the year; one horizontal rig in the Midland Basin appraisal program through
October; and one horizontal rig in the San Juan Basin Mancos appraisal program in the second half of 2015.
8
2015 Capital Summary
2015e Capital ($MM)
Midland Basin
Wolfcamp
Development
Appraisal
Spraberry
Development
Appraisal
Wolfberry
SWD/Facilities
Non-operated/Other
$
Delaware Basin
Bone Spring
Wolfcamp
Wolfbone
SWD/Facilities
Non-operated/Other
$
Other Permian
Waterflood injectors
Facilities/C02
Non-operated/Other
Operated Wells to Be Drilled
Gross (Net)
810
$
129 (122)
485
60
88
8
(82)
(8)
70
80
20
82
13
12
12
9
(12)
(12)
(8)
143
18
73
15
32
5
14 (13)
3 (2)
8 (8)
3 (3)
11
0
6
5
0 (0)
San Juan Basin/Other
Mancos
Facilities
Non-operated/Other
$
63
29
14
20
Net Carry-in/Carry
Out/Miscellaneous
Drilling & Development
$
18
$
1,045
Acquisitions/Lease Extensions/UPL
$
55
Total Capital
$
1,100
8
8
(8)
(8)
151 (143)
Note: “Facilities” capital includes artificial lift and central gathering facilities; “Other”
Capital includes payadds and refracs
Energen’s estimate of 2015 production (excluding volumes from the company’s San Juan Basin divestiture)
has been revised upward by 500,000 BOE to reflect 2
nd
quarter results and an additional 100,000 BOE of
nd
production in the 2 half of the year, primarily in the Midland Basin development program. Production would be
higher still absent high natural gas pipeline pressures that have materialized as a result of increased Delaware
Basin production industry-wide. As a result, Energen’s Reeves County production is expected to be negatively
impacted by approximately 200,000 BOE in the 2
nd
half of 2015.
Production for the year is now estimated to range from 22.2-23.2 MMBOE (60,820–63,560 boepd), with a
midpoint of 22.7 MMBOE (62,215 boepd). This reflects an increase of approximately 19 percent from
comparable, adjusted 2014 production volumes of 19.1 MMBOE.
9
The production midpoint in the 3rd quarter of 2015 is estimated to be 5.8 MMBOE (62,815 boepd). This is
down slightly from the prior estimate of 5.9 MMBOE (64,239 boepd) largely due to the timing of completions in
the Midland Basin and pipeline pressure issues in the Delaware Basin Wolfcamp, partially offset by a
rd
continuation of outstanding performance in the Delaware Basin Wolfcamp and 3 Bone Spring. The company
has added two frac crews in the Midland Basin and plans to run three for most of the third quarter. As a result,
th
production in the 4 quarter is estimated to increase substantially to a midpoint of 6.2 MMBOE (67,978 boepd).
Production by Play (Excluding San Juan Basin Divestiture)
Area
2015e Midpoint
2014
MMBOE
Midland Basin
Change
MMBOE
11.8
7.4
Wolfcamp/Spraberry/Cline
7.7
2.1
Wolfberry
4.1
5.3
Delaware Basin
5.3
5.8
3 Bone Spring/Other
3.7
4.6
Wolfcamp
1.6
1.2
Central Basin Platform
3.6
4.1
(12) %
Total Permian Basin
20.8
17.3
20 %
San Juan Basin/Other
1.9
1.8
6 %
22.7
19.1
19 %
rd
Total
59 %
(9) %
NOTE: Totals may not sum due to rounding
Production by Product (Excluding San Juan Basin Divestiture)
Commodity
2015e Midpoint
MMBOE
boepd
Oil
2014
MMBOE
boepd
% change
(boepd)
14.3
39,222
11.8
32,323
21 %
NGL
4.0
10,854
3.4
9,337
16 %
Natural Gas
4.4
12,139
3.9
10,660
14 %
22.7
62,215
19.1
52,320
19 %
Total Continuing Operations
Production by Basin/Quarter (Excluding San Juan Divestiture)
Basin
1Q15a
2Q15a
3Q15e Midpoint
4Q15e Midpoint
MMBOE boepd MMBOE boepd MMBOE boepd
MMBOE boepd
Midland Basin
2.3
25,778
3.0
32,495
3.0
32,250
3.6
38,804
Delaware Basin
1.2
13,611
1.5
15,934
1.4
15,283
1.2
13,543
Central Basin Platform/Other
0.9
10,100
0.9
10,088
0.9
9,891
0.9
9,663
San Juan Basin/Other
0.4
4,611
0.5
5,297
0.5
5,391
0.5
5,967
Total Production
4.9
54,100
5.8
63,802
5.8
62,815
6.2
67,978
NOTE: Totals may not sum due to rounding
10
Production by Commodity/Quarter (Excluding San Juan Basin Divestiture)
Commodity
1Q15a
2Q15a
3Q15e Midpoint
4Q15e Midpoint
MMBOE boepd MMBOE boepd MMBOE boepd
MMBOE boepd
Oil
3.2
35,922
3.6 39,505
3.6
39,022
3.9
42,370
NGL
0.7
8,133
1.1 11,648
1.0
11,293
1.1
12,283
Gas
0.9
10,044
1.2 12,648
1.2
12,500
1.2
13,326
Total Production
4.9
54,100
5.8 63,802
5.8
62,815
6.2
67,978
NOTE: Totals may not sum due to rounding
3Q15 AND CY15 FINANCIAL GUIDANCE
Energen’s estimated expenses, excluding San Juan Basin divestiture, are as follows:
Per BOE, except where noted
LOE (production costs, marketing & transportation)
3Q15
CY15
$10.00- $10.65
$9.25-$10.85
Production & ad valorem taxes (% of revenues, excluding hedges)
DD&A expense
7.8%
$24.50-$25.50
$24.30-$25.80
General & administrative expense, net*
$5.25-$5.40
$5.50-$5.85
Exploration expense (seismic, delay rentals, etc.)
$0.35-$0.45
$0.40-$0.50
Interest expense ($MM)
$10.0-$10.5
$40.0-$47.0
* Excludes $0.07 per BOE in 3Q15 and $1.63 per BOE in CY15 for pension and pension settlement expenses.
3Q15 and 2H15 Hedges
For the remaining 6 months of 2015, approximately 78 percent of the company’s production guidance midpoint
of 12.0 MMBOE is hedged. Hedges also are in place that limit the company’s exposure to the Midland to
Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 1.1 million
barrels of oil production at an average price of -$4.30 per barrel and the WTI Midland to WTI Cushing (sweet
oil) differential for 3.8 million barrels at an average price of -$4.55 per barrel. Energen estimates that
approximately 80 percent of its oil production for the remainder of the year will be sweet. Gas basis
assumptions for all open contracts (August-December) are -$0.12 per Mcf (basis actuals in July were
approximately -$0.10 per Mcf).
The company’s hedge position for the last six months of 2015 is:
Commodity
Oil
Natural Gas
Hedge Volumes
7.0 MMBO
13.8 Bcf
2H15e Production
Hedge %
NYMEXe Price
@ Midpoint
7.5 MMBO
14.3 Bcf
93 %
$
78.24 per barrel
97 %
$
4.27 per Mcf
Note: Known actuals included
11
In the table above, basin-specific contract prices for natural gas have been converted for comparability
purposes to a NYMEX-equivalent price by adding to them Energen’s assumed basis differentials. Average
realized oil and gas prices for Energen’s production associated with NYMEX contracts as well as for unhedged
production will reflect the impact of basis differentials; average realized oil prices also will reflect estimated oil
transportation charges of $2.26 per barrel for the second half of 2015; and average realized NGL prices will be
net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the Permian Basin
and $0.12-$0.17 per gallon in the San Juan Basin for the remainder of the year.
Energen’s assumptions for the commodity prices of unhedged production for the remainder of 2015 are $49.60
per barrel of oil (July-December), $2.90 per Mcf of gas (August-December), and $0.43 per gallon of NGL (JulyDecember). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (JulyDecember) are +$0.42 and +$0.69, respectively.
Every 1-cent change in the average price of NGL from $0.43 per gallon is estimated to have a cash flows
impact of $700,000.
Energen estimates that price realizations in the second half of 2015 (pre-hedge) will be approximately:
Crude oil (% of NYMEX/WTI)
94%
Natural gas (% of NYMEX/Henry Hub) 88%
NGL (after T&F) (% of NYMEX/WTI)
23%
For the 3rd quarter of 2015, approximately 81 percent of the company’s production guidance midpoint of 5.8
MMBOE is hedged. Hedges also are in place that limit the company’s exposure to the Midland to Cushing
differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 540,000 barrels of
oil production at an average price of -$4.30 per barrel and the WTI Midland to WTI Cushing (sweet oil)
differential for 1.9 million barrels at an average price of -$4.55 per barrel. Energen estimates that
approximately 79 percent of its oil production in the 3rd quarter of 2015 will be sweet. Gas basis assumptions
(August-September) are -$0.09 per Mcf (basis actuals in July were approximately -$0.10 per Mcf).
The company’s hedge position for the 3rd quarter of 2015 is:
Commodity
Hedge Volumes
CY15e Production
Hedge %
NYMEXe Price
Midpoint
Oil
3.5 MMBO
3.6 MMBO
97 %
$
78.21 per barrel
Natural Gas
6.8 Bcf
6.9 Bcf
99 %
$
4.25 per Mcf
Note: Known actuals included
In the table above, basin-specific contract prices for natural gas have been converted for comparability
purposes to a NYMEX-equivalent price by adding to them Energen’s assumed basis differentials.
12
Average realized oil and gas prices for Energen’s production associated with NYMEX contracts as well as for
unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect
estimated oil transportation charges of $2.31 per barrel in the 3rd quarter of 2015; and average realized NGL
prices will be net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the
Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin in the 3rd quarter of 2015.
Energen’s assumptions for the commodity prices of unhedged production in the 3rd quarter of 2015 are $49.60
per barrel of oil (July-September), $2.80 per Mcf of gas (August-September), and $0.43 per gallon of NGL
(July-September). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil
(July-September) are +$0.46 and +$1.01, respectively.
Every 1-cent change in the average price of NGL from $0.43 per gallon is estimated to have a cash flows
impact of $335,000.
rd
Energen estimates that price realizations in the 3 quarter (pre-hedge) will be approximately:
Crude oil (% of NYMEX/WTI)
95%
Natural gas (% of NYMEX/Henry Hub) 89%
NGL (after T&F) (% of NYMEX/WTI)
22%
Conference Call
Energen will hold its quarterly conference call Friday, August 7, at 11:00 a.m. EDT. Members of the investment
community 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 through Web site, www.energen.com.
Energen Corporation is an oil and gas exploration and production company with headquarters in Birmingham, Alabama.
The company has 1.1 billion barrels of oil-equivalent proved, probable, and possible reserves and another 2.2 billion
barrels of oil-equivalent contingent resources. These all-domestic reserves and resources are located primarily in the
Permian Basin in west Texas. For more information, go to http://www.energen.com.
FORWARD LOOKING STATEMENT: 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 timing and amount of future production of oil, natural gas liquids and
natural gas, price realizations, nature and timing of capital expenditures for exploration and development, plans for funding
operations and drilling program capital expenditures, 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 filing. 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.
Financial, operating, and support data pertaining to all reporting periods included in this release are unaudited and subject to revision.
13
Non-GAAP Financial Measures
Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles)
which excludes certain non-cash mark-to-market derivative financial instruments. Adjusted income from continuing
operations further excludes impairment losses, income associated with certain divestments, gains and losses on
disposal of discontinued operations and income and losses from discontinued operations. 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.
Energen Net Income ($ in millions except per share data)
Net Income (Loss) All Operations (GAAP)
Non-cash mark-to-market losses (net of $41.7 tax)
Asset impairment, other (net of $24.0 tax)
Loss associated w/ San Juan Basin divestment (net of $0.9 tax)
Adjusted Income from Continuing Operations (Non-GAAP)
Quarter Ended 6/30/2015
Per Diluted
Net Income
Share
(111.6)
(1.52)
75.1
1.02
42.9
0.58
1.2
0.02
7.7
0.10
Energen Net Income ($ in millions except per share data)
Net Income (Loss) All Operations (GAAP)
Non-cash mark-to-market losses (net of $21.5 tax)
Asset impairment, other (net of $0.9 tax)
Income associated w/ San Juan Basin divestment (net of $5.9 tax)
Adjusted Net Income from All Operations (Non-GAAP)
Loss from discontinued operations (net of $3.0 tax)
Adjusted Income from Continuing Operations (Non-GAAP)
Quarter Ended 6/30/2014
Per Diluted
Share
Net Income
(8.0)
(0.11)
38.1
0.52
1.6
0.02
(10.6)
(0.15)
21.2
0.29
4.8
0.07
26.0
0.36
Note: Amounts may not sum due to rounding
14
Non-GAAP Financial Measures
Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP
financial measure (GAAP refers to generally accepted accounting principles). Adjusted EBITDAX from continuing operations
further excludes income associated with certain divestments, impairment losses, certain non-cash mark-to-market derivative
financial instruments, income and losses from discontinued operations and gains and losses on disposal of discontinued
operations. Energen believes these measures allow analysts and investors to understand the financial performance of the
company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further,
this measure is useful in comparing the company and other oil and gas producing companies.
Reconciliation To GAAP Information
($ in millions)
Energen Net Income (Loss) (GAAP)
(Income) Loss associated w/ San Juan Basin divestment, net of tax
Adjusted Net Income from Continuing Operations (Non-GAAP)
Interest expense *
Income tax expense (benefit) *
Depreciation, depletion and amortization *
Accretion expense *
Exploration expense *
Dry hole expense *
Adjustment for asset impairment *
Adjustment for mark-to-market losses
Adjustment for income from discontinued operations, net of tax
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)
Quarter Ended 6/30
2015
(111.6)
1.2
(110.4)
11.2
(60.4)
149.8
1.7
4.5
6.5
60.4
116.9
0.0
180.3
2014
(8.0)
(10.6)
(18.6)
8.0
(6.9)
121.9
1.5
0.0
1.2
1.3
59.6
4.8
172.9
Note: Amounts may not sum due to rounding
* Amount adjusted to exclude San Juan Basin divestment. See reconciliation to
GAAP Information for the Quarter Ended 6/30/2015 and 6/30/2014.
15
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 the divestment of assets held in the San Juan Basin 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 San Juan Divestment
Reconciliation to GAAP Information
Quarter Ended
June 30, 2015
(in thousands except per share and production data)
GAAP
Revenues
Oil, natural gas liquids and natural gas sales
Gain (loss) on derivative instruments
Total Revenues
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production
Production and ad valorem taxes
O&G Depreciation, depletion and amortization
FF&E Depreciation, depletion and amortization
Asset impairment
Exploration
General and administrative
Accretion of discount on asset retirement obligations
(Gain) loss on sale of assets and other
Total costs and expenses
Operating Income (Loss)
Other Income/(Expense)
Interest Expense
Other income
Total other expense
$
$/BOE
219,290
(50,964)
168,326
53,581
13,352
148,374
1,469
60,413
11,018
38,652
1,669
1,476
330,004
(161,678)
San Juan Basin
$
$9.15
$2.28
$25.35
$0.25
592
592
1,886
(174)
(1)
994
2,705
(2,113)
$6.60
$/BOE
Non-GAAP
$
$40.13
($3.70)
$0.00
$0.00
218,698
(50,964)
167,734
51,695
13,526
148,374
1,469
60,413
11,018
38,653
1,669
482
327,299
(159,565)
($0.02)
(11,244)
41
(11,203)
-
(11,244)
41
(11,203)
(172,881)
(61,280)
(111,601)
(2,113)
(864)
(1,249)
(170,768)
(60,416)
(110,352)
$
(1,249)
$
(110,352)
Income (Loss) from Continuing Operations Before
Income Taxes
Income tax expense (benefit)
Income (Loss) From Continuing Operations
Discontinued Operations, net of tax
Income from discontinued operations
Loss on Disposal of discontinued ops
Income from discontinued ops
Net Income (Loss)
$
(111,601)
Diluted Earnings Per Average Common Share
Continuing Operations
Discontinued Operations
Net Income (Loss)
$
$
$
(1.52)
(1.52)
$
$
$
(0.02)
(0.02)
$
$
$
(1.50)
(1.50)
Basic earning Per Average Common Share
Continuing Operations
Discontinued Operations
Net Income (Loss)
$
$
$
(1.52)
(1.52)
$
$
$
(0.02)
(0.02)
$
$
$
(1.50)
(1.50)
Oil
NGL
Gas
Total Production (mboe)
Total Production (boepd)
3,594
1,070
1,189
5,853
64,319
(1)
10
38
47
516
$/BOE
$8.90
$2.33
$25.56
$0.25
$6.66
3,595
1,060
1,151
5,806
63,802
Note: Amounts may not sum due to rounding
16
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 the divestment of assets held in the San Juan Basin 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 San Juan Divestment
Reconciliation to GAAP Information
Quarter Ended
June 30, 2014
(in thousands except per share and production data)
GAAP
Revenues
Oil, natural gas liquids and natural gas sales
Gain (loss) on derivative instruments
Total Revenues
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production
Production and ad valorem taxes
O&G Depreciation, depletion and amortization
FF&E Depreciation, depletion and amortization
Asset impairment
Exploration
General and administrative
Accretion of discount on asset retirement obligations
(Gain) loss on sale of assets and other
Total costs and expenses
Operating Income (Loss)
Other Income/(Expense)
Interest Expense
Other income
Total other expense
$
$/BOE
355,852
(84,846)
271,006
64,697
28,049
135,164
1,080
1,342
1,233
33,542
1,883
909
267,899
3,107
San Juan Basin
$
$10.20
$4.42
$21.31
$0.17
43,086
6,278
49,364
15,017
3,750
14,288
62
3
(612)
388
32,896
16,468
$5.29
$/BOE
Non-GAAP
$
$9.21
$2.30
$8.77
$0.04
312,766
(91,124)
221,642
49,680
24,299
120,876
1,018
1,342
1,230
34,154
1,495
909
235,003
(13,361)
($0.38)
(7,964)
687
(7,277)
-
(7,964)
687
(7,277)
(4,170)
(1,016)
(3,154)
16,468
5,853
10,615
(20,638)
(6,869)
(13,769)
$
10,615
$
(4,799)
(4,799)
(18,568)
Income (Loss) from Continuing Operations Before
Income Taxes
Income tax expense (benefit)
Income (Loss) From Continuing Operations
Discontinued Operations, net of tax
Income (Loss) from discontinued operations
Loss on Disposal of discontinued ops
Income from discontinued ops
Net Income (Loss)
$
(4,799)
(4,799)
(7,953)
Diluted Earnings Per Average Common Share
Continuing Operations
Discontinued Operations
Net Income (Loss)
$
$
$
(0.04)
(0.07)
(0.11)
$
$
$
0.15
0.15
$
$
$
(0.19)
(0.07)
(0.26)
Basic earning Per Average Common Share
Continuing Operations
Discontinued Operations
Net Income (Loss)
$
$
$
(0.04)
(0.07)
(0.11)
$
$
$
0.15
0.15
$
$
$
(0.19)
(0.07)
(0.26)
Oil
NGL
Gas
Total Production (mboe)
Total Production (boepd)
2,833
1,065
2,446
6,344
69,714
3
167
1,460
1,630
17,912
$/BOE
$10.54
$5.15
$25.63
$0.22
$7.25
2,830
898
986
4,714
51,802
Note: Amounts may not sum due to rounding
17
Non-GAAP Financial Measures
Excluding production associated with certain divestments is a Non-GAAP financial measure (GAAP refers to generally
accepted accounting principles). Energen believes excluding data associated with the divestment of assets held in
the San Juan Basin provides analysts and investors useful information to understand the financial performance of the
company from ongoing business operations. Further, this measure is useful in comparing the company and other oil
and gas producing companies operating primarily in the Permian Basin.
Energen Production Excluding San Juan Divestment
Reconciliation to GAAP Information
Quarter Ended
March 31, 2015
GAAP
Oil
NGL
Gas
Total Production (mboe)
Total Production (boepd)
San Juan Basin
3,235
861
2,213
6,309
70,100
Energen Production Excluding San Juan Divestment
Reconciliation to GAAP Information
3,233
732
904
4,869
54,100
Year-to-Date Ended
December 31, 2014
GAAP
Oil
NGL
Gas
Total Production (mboe)
Total Production (boepd)
2
129
1,309
1,440
16,000
Non-GAAP
11,814
4,103
9,767
25,684
70,367
San Juan Basin
16
695
5,876
6,587
18,047
Non-GAAP
11,798
3,408
3,891
19,097
52,320
Note: Amounts may not sum due to rounding
18
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 3 months ending June 30, 2015 and 2014
2nd Quarter
2015
(in thousands, except per share data)
Revenues
Oil, natural gas liquids and natural gas sales
Loss on derivative instruments, net
$
Total revenues
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production
Production and ad valorem taxes
Depreciation, depletion and amortization
Asset impairment
Exploration
General and administrative
Accretion of discount on asset retirement obligations
(Gain) loss on sale of assets and other
Total costs and expenses
2014
219,290
(50,964)
$
355,852
(84,846)
Change
$
(136,562)
33,882
168,326
271,006
(102,680)
53,581
13,352
149,843
60,413
11,018
38,652
1,669
1,476
64,697
28,049
136,244
1,342
1,233
33,542
1,883
909
(11,116)
(14,697)
13,599
59,071
9,785
5,110
(214)
567
330,004
267,899
62,105
Operating Income (Loss)
(161,678)
3,107
Other Income (Expense)
Interest expense
Other income
(11,244)
41
(7,964)
687
(3,280)
(646)
(11,203)
(7,277)
(3,926)
Loss From Continuing Operations
Before Income Taxes
Income tax expense (benefit)
(172,881)
(61,280)
(4,170)
(1,016)
(168,711)
(60,264)
Loss From Continuing Operations
(111,601)
(3,154)
(108,447)
Total other expense
(164,785)
Discontinued Operations, net of tax
Loss from discontinued operations
−
(4,799)
4,799
Loss From Discontinued Operations
−
(4,799)
4,799
Net Income (Loss)
$
(111,601)
$
(7,953)
$
(103,648)
Diluted Earnings Per Average Common Share
Continuing operations
Discontinued operations
$
(1.52)
−
$
(0.04)
(0.07)
$
(1.48)
0.07
Net Income (Loss)
$
(1.52)
$
(0.11)
$
(1.41)
Basic Earnings Per Average Common Share
Continuing operations
Discontinued operations
$
(1.52)
−
$
(0.04)
(0.07)
$
(1.48)
0.07
Net Income (Loss)
$
(1.52)
$
(0.11)
$
(1.41)
Diluted Avg. Common Shares Outstanding
73,452
72,851
601
Basic Avg. Common Shares Outstanding
73,452
72,851
601
Dividends Per Common Share
$
0.02
$
0.15
$
(0.13)
19
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 6 months ending June 30, 2015 and 2014
Year-to-date
2015
(in thousands, except per share data)
Revenues
Oil, natural gas liquids and natural gas sales
Loss on derivative instruments, net
$
2014
407,112
(16,928)
$
706,674
(138,237)
Change
$
(299,562)
121,309
390,184
568,437
(178,253)
121,335
32,417
284,224
66,996
11,781
70,707
3,679
(26,868)
132,141
55,373
260,464
2,588
12,801
65,715
3,726
1,062
(10,806)
(22,956)
23,760
64,408
(1,020)
4,992
(47)
(27,930)
564,271
533,870
30,401
Operating Income (Loss)
(174,087)
34,567
(208,654)
Other Income (Expense)
Interest expense
Other income
(23,002)
87
(15,852)
1,010
(7,150)
(923)
(22,915)
(14,842)
(8,073)
Income (Loss) From Continuing Operations
Before Income Taxes
Income tax expense (benefit)
(197,002)
(69,981)
19,725
7,232
(216,727)
(77,213)
Income (Loss) From Continuing Operations
(127,021)
12,493
(139,514)
Total revenues
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production
Production and ad valorem taxes
Depreciation, depletion and amortization
Asset impairment
Exploration
General and administrative
Accretion of discount on asset retirement obligations
(Gain) loss on sale of assets and other
Total costs and expenses
Total other expense
Discontinued Operations, net of tax
Income from discontinued operations
Loss on disposal of discontinued operations
−
−
33,920
(1,050)
(33,920)
1,050
Income From Discontinued Operations
−
32,870
(32,870)
Net Income (Loss)
$
(127,021)
$
45,363
$
(172,384)
Diluted Earnings Per Average Common Share
Continuing operations
Discontinued operations
$
(1.74)
−
$
0.17
0.45
$
(1.91)
(0.45)
Net Income (Loss)
$
(1.74)
$
0.62
$
(2.36)
Basic Earnings Per Average Common Share
Continuing operations
Discontinued operations
$
(1.74)
−
$
0.17
0.45
$
(1.91)
(0.45)
Net Income (Loss)
$
(1.74)
$
0.62
$
(2.36)
Diluted Avg. Common Shares Outstanding
73,143
73,031
112
Basic Avg. Common Shares Outstanding
73,143
72,737
406
Dividends Per Common Share
$
0.04
$
0.30
$
(0.26)
20
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of June 30, 2015 and December 31, 2014
(in thousands)
ASSETS
Current Assets
Cash and cash equivalents
Accounts receivable, net of allowance
Inventories
Assets held for sale
Derivative instruments
Prepayments and other
June 30, 2015
December 31, 2014
$
$
Total current assets
Property, Plant and Equipment
Oil and natural gas properties, net
Other property and equipment, net
Total property, plant and equipment, net
Other assets
TOTAL ASSETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable
Accrued taxes
Accrued wages and benefits
Accrued capital costs
Revenue and royalty payable
Liabilities related to assets held for sale
Pension liabilities
Deferred income taxes
Derivative instruments
Other
1,852
157,678
14,251
395,797
322,337
27,445
318,270
919,360
5,493,509
46,773
5,152,748
46,389
5,540,282
5,199,137
14,094
19,761
$
5,872,646
$
6,138,258
$
94,953
14,055
22,217
110,485
62,179
−
29,616
11,970
10,220
23,220
$
101,453
5,530
21,553
207,461
72,047
24,230
24,609
79,164
988
23,288
Total current liabilities
Long-term debt
Asset retirement obligations
Deferred income taxes
Noncurrent derivative instruments
Other long-term liabilities
Total liabilities
Total Shareholders’ Equity
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
1,510
128,564
17,988
−
147,789
22,419
$
378,915
560,323
686,575
99,049
1,001,251
3,902
12,906
1,038,563
94,060
1,000,486
−
30,222
2,182,598
2,723,654
3,690,048
3,414,604
5,872,646
$
6,138,258
21
SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 3 months ending June 30, 2015 and 2014
nd
2
2015
(in thousands, except sales price and per unit data)
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
$
188,599
Oil
14,781
Natural gas liquids
15,910
Natural gas
$
219,290
Total
Open non-cash mark-to-market gains (losses) on derivative instruments
$
(103,734)
Oil
−
Natural gas liquids
(13,133)
Natural gas
$
(116,867)
Total
Closed gains (losses) on derivative instruments
Oil
Natural gas liquids
Natural gas
Total
Total revenues
Quarter
$
$
$
Production volumes
Oil (MBbl)
Natural gas liquids (MMgal)
Natural gas (MMcf)
Total production volumes (MBOE)
Average daily production volumes
Oil (MBbl/d)
Natural gas liquids (MMgal/d)
Natural gas (MMcf/d)
Total average daily production volumes (MBOE/d)
55,330
−
10,573
65,903
168,326
2014
$
$
$
$
$
$
$
Change
262,746
31,163
61,943
355,852
$
(66,172)
40
6,511
(59,621)
$
(25,754)
159
370
(25,225)
271,006
$
$
$
$
$
(74,147)
(16,382)
(46,033)
(136,562)
(37,562)
(40)
(19,644)
(57,246)
81,084
(159)
10,203
91,128
(102,680)
3,594
44.9
7,134
5,853
2,833
44.7
14,676
6,344
761
0.20
(7,542)
(491)
39.5
0.5
78.4
64.3
31.1
0.5
161.3
69.7
8.4
−
(82.9)
(5.4)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
$
67.87
$
83.65
$
Oil (per barrel)
$
0.33
$
0.70
$
Natural gas liquids (per gallon)
$
3.71
$
4.25
$
Natural gas (per Mcf)
(15.78)
(0.37)
(0.54)
Average realized prices excluding effects of all derivative instruments
$
52.48
Oil (per barrel)
$
0.33
Natural gas liquids (per gallon)
$
2.23
Natural gas (per Mcf)
$
$
$
92.74
0.70
4.22
$
$
$
(40.26)
(0.37)
(1.99)
Costs per BOE
Oil, natural gas liquids and natural gas
production expenses
Production and ad valorem taxes
Depreciation, depletion and amortization
Exploration expense
General and administrative*
Net capital expenditures
$
$
$
$
$
$
10.20
4.42
21.48
0.19
5.29
322,572
$
$
$
$
$
$
(1.05)
(2.14)
4.12
1.69
1.31
(37,808)
$
$
$
$
$
$
9.15
2.28
25.60
1.88
6.60
284,764
*Includes pension and pension settlement expenses of $0.19 and $0.50 for the three months ended June 30,
2015 and 2014, respectively.
22
SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 6 months ending June 30, 2015 and 2014
Year-to-date
2015
(in thousands, except sales price and per unit data)
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
$
330,627
Oil
25,615
Natural gas liquids
50,870
Natural gas
$
407,112
Total
Open non-cash mark-to-market gains (losses) on derivative instruments
$
(155,503)
Oil
−
Natural gas liquids
(21,015)
Natural gas
$
(176,518)
Total
Closed gains (losses) on derivative instruments
Oil
Natural gas liquids
Natural gas
Total
Total revenues
$
$
$
Production volumes
Oil (MBbl)
Natural gas liquids (MMgal)
Natural gas (MMcf)
Total production volumes (MBOE)
Average daily production volumes
Oil (MBbl/d)
Natural gas liquids (MMgal/d)
Natural gas (MMcf/d)
Total average daily production volumes (MBOE/d)
132,813
−
26,777
159,590
390,184
2014
$
$
$
$
$
$
$
Change
516,505
59,366
130,803
706,674
$
(87,636)
327
(5,993)
(93,302)
$
(40,556)
355
(4,734)
(44,935)
568,437
$
$
$
$
$
(185,878)
(33,751)
(79,933)
(299,562)
(67,867)
(327)
(15,022)
(83,216)
173,369
(355)
31,511
204,525
(178,253)
6,829
81.1
20,412
12,162
5,584
82.7
28,800
12,352
1,245
(1.6)
(8,388)
(190)
37.7
0.5
112.8
67.2
30.9
0.5
159.1
68.2
6.8
−
(46.3)
(1.0)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
$
67.86
$
85.23
$
Oil (per barrel)
$
0.32
$
0.72
$
Natural gas liquids (per gallon)
$
3.80
$
4.38
$
Natural gas (per Mcf)
(17.37)
(0.40)
(0.58)
Average realized prices excluding effects of all derivative instruments
$
48.42
Oil (per barrel)
$
0.32
Natural gas liquids (per gallon)
$
2.49
Natural gas (per Mcf)
$
$
$
92.50
0.72
4.54
$
$
$
(44.08)
(0.40)
(2.05)
Costs per BOE
Oil, natural gas liquids and natural gas
production expenses
Production and ad valorem taxes
Depreciation, depletion and amortization
Exploration expense
General and administrative*
Net capital expenditures
$
$
$
$
$
$
10.70
4.48
21.09
1.04
5.32
594,268
$
$
$
$
$
$
(0.72)
(1.81)
2.28
(0.07)
0.49
66,323
$
$
$
$
$
$
9.98
2.67
23.37
0.97
5.81
660,591
*Includes pension and pension settlement expenses of $0.34 and $0.79 for the six months ended June 30, 2015
and 2014, respectively.
23