Energen’s Gen 3 Wells Continue to Deliver Outstanding Results BIRMINGHAM, Ala.
3Q17 Production Beats Guidance by 9%; All Commodities Exceed
Expectations
4Q17 Production Guidance Raised 5%
Per-Unit LOE and SG&A Decrease Substantially Again in 3Q17
NOTE: 3Q17 conference call slides available at www.energen.com
Energen Corporation (NYSE: EGN) (“Energen” or the “company”) today
announced financial and operating results for the third quarter ended
September 30, 2017.
FINANCIAL AND OPERATING HIGHLIGHTS
PRODUCTION
-
3Q17 production of 81.3 mboepd exceeded guidance by 9% and
surpassed 2Q17 production by 12%.
-
3Q17 oil production grew 9% from 2Q17.
-
Revised CY17 production of 73.2 mboepd is on track to exceed CY16
volumes by 34% (prior estimate was 29%).
-
YOY production growth in Midland and Delaware basins is now
estimated to be 43% as company focuses on development of multiple
horizontal shale plays.
-
4Q17 production estimate raised for all commodities; YOY growth in
the 4Q exit rate is now estimated to be 60%.
EARNINGS AND EXPENSES
-
3Q17 adjusted EBITDAX of $174 mm grew 22% from 2Q17 and beat
internal expectations by 14%.
-
Per-unit LOE (including marketing and transportation) beat the
guidance midpoint by 17%.
-
Per unit SG&A beat the guidance midpoint by 12%.
CAPITAL EXPENDITURES
-
2017 drilling and development capital range is unchanged at $850 -
$900 mm.
-
Energen closed on an additional 1,300 net acres of unproved
leasehold in 3Q17, bringing its YTD acquisition of unproved bolt-on
acreage to 11,000 net acres for ≈$235 mm, or ≈$21,400/acre.
3Q17 WELL RESULTS
-
26 gross (25 net) wells in the Midland and Delaware basins were
turned to production in 3Q17; 77% are multi-zone pattern wells
completed in batches.
-
The cumulative production of 80 Gen 3 wells are performing at or
above the highest EUR type curve and significantly
outperforming the midpoint EUR type curve; 78% are multi-zone pattern
wells completed in batches.
-
Public data continues to show that Energen’s Gen 3 wells in the
Midland and Delaware basins are outperforming other operators’ wells.
Comments from the CEO
“Energen’s execution and operational success continued in the third
quarter of 2017,” said Energen Chief Executive Officer James McManus.
“Once again, we delivered on our drilling and development plans; we
exceeded our expectations for oil and total production; and we further
reduced our LOE and G&A.
“Our Gen 3 wells continue to perform at or above our highest EUR type
curves and at or above wells completed by other operators. Importantly,
we expect our Gen 3 multi-zone pattern wells to continue driving
production growth as we move forward. We have increased our guidance for
4th quarter production in all commodities, with
estimated total production up 5 percent; and we now expect
year-over-year production growth in 2017 to be 34 percent.
“During the 3rd quarter, we continued to
execute on our bolt-on acquisition program, which we believe has created
significant value for Energen. Over the last 21 months, we have added
approximately 20,300 net acres in prime Delaware and Midland basin
locations for an average price of about $17,500 an acre,” McManus said.
“We are extremely pleased with our performance this quarter and very
excited about our future prospects as we successfully implement our 2017
drilling and development program and plan for 2018. We are confident
that Energen is well-positioned to continue delivering strong results
and creating shareholder value now and in the future.”
Operations Update
In the third quarter of 2017, Energen turned to production 17 gross (16
net) wells in the Midland Basin and 9 gross (9 net) wells in the
Delaware Basin; 77 percent are multi-zone pattern wells completed in
batches. The company is currently operating six horizontal drilling rigs
and two frac crews.
2017 First Production/Flow back (Operated Horizontal Wells –
Gross/Net)
|
|
1Q17a
|
|
2Q17a
|
|
3Q17a
|
|
4Q17e
|
|
CY17e
|
Midland Basin
|
|
10/9
|
|
27/27
|
|
17/16
|
|
20/16
|
|
74/68
|
Delaware Basin
|
|
2/2
|
|
18/18
|
|
9/9
|
|
5/5
|
|
34/34
|
|
|
|
|
|
|
|
|
|
|
|
3Q17 Wells Turned to Production
Area
|
|
# of Wells
|
|
Average Completed Lateral Length
|
|
Avg. Peak 24- Hour IP
|
|
Avg. Peak 30-day IP
|
|
|
|
Boepd
|
|
%Oil
|
|
Boepd
|
|
%Oil
|
Delaware Basin†
|
|
7
|
|
Wolfcamp A (6) Wolfcamp B (1)
|
|
8,851’
|
|
2,806
|
|
55
|
|
2,204
|
|
51
|
Northern Midland Basin††
|
|
7
|
|
Wolfcamp A (3) Wolfcamp B (4)
|
|
9,189’
|
|
1,466
|
|
81
|
|
1,070
|
|
83
|
† Excludes 2 Wolfcamp BC wells ††
Excludes 10 Northern Midland Basin Spraberry interval wells due to
timing of first production or disposal-related choke management
For 80 Gen 3 wells drilled to date (78 percent of which were multi-zone
pattern wells completed in batches), the average cumulative production
uplift of wells in each formation group (normalized to 10,000’) is
performing at or above the highest EUR type curve – and significantly
outperforming the midpoint EUR type curve – identified for wells in that
group completed with pre-Gen 3 frac designs. These are key measures of
success for Energen’s latest frac design.
Relative to the midpoint EUR type curve, the average cumulative
production uplift of the Gen 3 wells normalized to 10,000’ is:
-
≈21% over a 1.75 MMBOE type curve at 340 days for 27 Delaware Basin
Wolfcamp A and B wells – 56% are multi-zone pattern wells completed in
batches
-
≈40% over a 1.2 MMBOE type curve at 175 days for 18 wells in the
Spraberry package – 89% are multi-zone pattern wells completed in
batches
-
≈6% over a 1.2 MMBOE type curve at 250 days for 17 northern Midland
Basin Wolfcamp A and B wells – 76% are multi-zone pattern wells
completed in batches
-
≈11% over a 1.2 MMBOE type curve at 250 days for 16 central Midland
Basin Wolfcamp A and B wells – 100% are multi-zone pattern wells in
batches
-
≈45% over an 850 MBOE type curve at 240 days for 2 central Midland
Basin Lower Spraberry wells – 100% are multi-zone pattern wells
completed in batches
In another assessment of success, the average cumulative production of
Energen’s Midland Basin Gen 3 multi-zone pattern wells completed in
batches continues to outperform other operators’ pattern wells, and the
average cumulative production of Energen’s Gen 3 wells (pattern and
stand-alone) in the Midland and Delaware basins is outperforming other
operators’ wells with proppant loads of 1,700-2,500 pounds per foot;
Energen’s average proppant loading is near the low end of this range at
approximately 1,800 pounds in the Midland Basin and 1,900 pounds in the
Delaware Basin.
The company attributes this outperformance to completing the wells in
multi-zone batches instead of completing them as offset pattern wells.
Utilizing simultaneous, multi-zone pattern development allows all wells
to be completed at the original reservoir pressure, which should
maximize reservoir productivity. In offset pattern well development, the
original stand-alone well causes the reservoir pressure to drop and
reduces the productivity of all subsequent wells drilled.
Bolt-on Lease Acquisitions Continue
During 3Q17, Energen closed on an additional 1,300 net acres of unproved
leasehold in the Permian Basin for approximately $20 million. Year to
date, Energen has acquired more than 11,000 net acres for approximately
$235 million, or an average price of some $21,400 per acre. The company
also has purchased 690 net mineral acres primarily in the Delaware Basin
in the first nine months of 2017 for approximately $20 million.
Over the last 21 months (CY16 and YTD17), Energen’s bolt-on acquisition
program has added approximately 20,300 net lease acres in prime Delaware
and Midland basin locations for some $355 million, or an average price
of less than $17,500 per acre.
2017 Capital Overview
Energen’s estimate of capital spending for drilling and development in
2017 remains unchanged at $850-$900 million.
Capital Summary by Basin
|
|
2017e Capital ($MM)
|
Midland Basin
|
|
$ 470 - 490
|
Delaware Basin
|
|
$ 375 - 405
|
Central Basin, ARO, Other
|
|
$ 5
|
Drilling & Development Capital
|
|
$ 850 - 900
|
Acquisitions/Unproved Leasehold
|
|
$ 265
|
Total Capital Expenditures
|
|
$ 1,115 - 1,165
|
|
|
|
Liquidity and Leverage Update
The fall redetermination cycle is under way. While Energen estimates
that its borrowing base will increase from $1.4 billion to $1.7 billion,
the company expects its aggregate commitment under the credit facility
will remain unchanged at $1.05 billion. At September 30, 2017, Energen
had cash of $0.3 million, long-term debt of $527.8 million, and $238.0
million drawn on its $1.05 billion line of credit. The company estimates
that net debt-to-adjusted EBITDAX at year-end 2017 will range from
1.2x-1.3x.
3Q17 Financial Results
For the 3 months ended September 30, 2017, Energen reported a GAAP net
loss from all operations of $(18.5 million), or $(0.19) per diluted
share. Adjusting for a non-cash loss on mark-to-market derivatives of
$(40.2 million) and other miscellaneous items totaling $2.5 million,
Energen had adjusted net income in 3Q17 of $19.2 million, or $0.20 per
diluted share. This compares with an adjusted loss in 3Q16 of $(21.4
million), or $(0.22) per diluted share. [See “Non-GAAP Financial
Measures” beginning on pp 8 for more information and reconciliation.]
Energen’s adjusted 3Q17 net income of $19.2 million exceeded internal
expectations by $6.6 million largely due to better-than-expected
performance of wells completed with Gen 3 fracs, less-than-expected
lease operating expense (LOE) and net salaries and general and
administrative expense (SG&A), and higher realized oil prices. Partially
offsetting these gains was increased depreciation, depletion, and
amortization expense (DD&A) largely due to increased production.
Energen’s adjusted EBITDAX totaled $174.0 million in the 3rd quarter of
2017, increased 22 percent from the second quarter, and exceeded
internal expectations by 14 percent. In the same period a year ago,
Energen’s adjusted EBITDAX totaled $84.8 million. [See “Non-GAAP
Financial Measures” beginning on pp 8 for more information and
reconciliation.]
3Q17 Production (mboepd)
Commodity
|
|
3Q17
|
|
Actual
|
|
Guidance
|
|
% ∆
|
Oil
|
|
49.0
|
|
47.9
|
|
2
|
NGL
|
|
15.7
|
|
12.9
|
|
22
|
Natural Gas
|
|
16.6
|
|
13.9
|
|
19
|
Total
|
|
81.3
|
|
74.8
|
|
9
|
|
|
|
|
|
|
|
Area
|
|
3Q17
|
|
Actual
|
|
Guidance
|
|
% ∆
|
Midland Basin
|
|
44.8
|
|
40.6
|
|
10
|
|
Delaware Basin
|
|
28.7
|
|
26.2
|
|
10
|
|
Central Basin/Other
|
|
7.9
|
|
8.0
|
|
(1
|
)
|
Total
|
|
81.3
|
|
74.8
|
|
9
|
|
Note: Totals in production tables above may not sum due to rounding.
3Q17 Expenses
|
|
|
Per BOE, except where noted
|
|
3Q17
|
|
Actual
|
Midpoint
|
|
% ∆
|
LOE (production costs, marketing & transportation)
|
|
$
|
5.95
|
|
$
|
7.15
|
|
|
(17
|
)
|
Production & ad valorem taxes (% of revenues exc. hedges)
|
|
|
6.2
|
%
|
|
6.4
|
%
|
|
(3
|
)
|
DD&A
|
|
$
|
17.46
|
|
$
|
17.25
|
|
|
1
|
|
SG&A
|
|
$
|
2.87
|
|
$
|
3.25
|
|
|
(12
|
)
|
Exploration (includes seismic, delay rentals, etc.)
|
|
$
|
0.08
|
|
$
|
0.13
|
|
|
(38
|
)
|
Interest ($mm)
|
|
$
|
9.9
|
|
$
|
10.0
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
3Q17 Average Realized Prices
|
|
|
|
|
Commodity
|
|
With Hedges
|
|
W/O Hedges
|
Oil (per barrel)
|
|
$
|
46.27
|
|
$
|
45.07
|
NGL (per gallon)
|
|
$
|
0.39
|
|
$
|
0.42
|
Natural Gas (per mcf)
|
|
$
|
2.35
|
|
$
|
2.22
|
|
|
|
|
|
|
|
CY17 Guidance
Energen today raised its production guidance for 2017 by 4 percent to
73.2 mboepd to reflect the company’s strong 3Q17 performance as well as
a 5 percent increase in its estimated 4Q17 production. Energen now
expects 4Q17 volumes to reach 85.7 mboepd for an increase of 60 percent
from the same period a year ago. On the strength of its Generation 3
frac design, Energen sees YOY production growth in 2017 of 34 percent,
up from the prior estimate of 29 percent.
Production (mboepd)
By Basin
|
|
1Q17a
|
|
2Q17a
|
|
3Q17a
|
|
4Q17e
|
|
CY17e
|
Midland Basin
|
|
31.8
|
|
41.3
|
|
44.8
|
|
45.4
|
|
40.8
|
Delaware Basin
|
|
12.8
|
|
23.4
|
|
28.7
|
|
32.4
|
|
24.4
|
Central Basin Platform/Other
|
|
8.3
|
|
7.9
|
|
7.9
|
|
7.8
|
|
8.0
|
Total
|
|
52.8
|
|
72.5
|
|
81.3
|
|
85.7
|
|
73.2
|
|
|
|
|
|
|
|
|
|
|
|
By Commodity
|
|
1Q17a
|
|
2Q17a
|
|
3Q17a
|
|
4Q17e
|
|
CY17e
|
Oil
|
|
33.3
|
|
45.1
|
|
49.0
|
|
54.0
|
|
45.4
|
NGL
|
|
8.9
|
|
13.5
|
|
15.7
|
|
14.9
|
|
13.3
|
Gas
|
|
10.6
|
|
13.9
|
|
16.6
|
|
16.8
|
|
14.5
|
Total
|
|
52.8
|
|
72.5
|
|
81.3
|
|
85.7
|
|
73.2
|
Note: Totals in production tables above may not sum due to rounding.
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
Per BOE, except where noted
|
|
1Q17a
|
|
2Q17a
|
|
3Q17a
|
|
4Q17e
|
|
CY17e
|
LOE*
|
|
$ 8.68
|
|
$ 6.66
|
|
$ 5.95
|
|
$6.55 - $6.85
|
|
$6.70 - $7.00
|
Production & ad valorem taxes**
|
|
7.3%
|
|
6.0%
|
|
6.2%
|
|
6.2%
|
|
6.4%
|
DD&A expense†
|
|
$ 20.71
|
|
$ 18.25
|
|
$ 17.46
|
|
$16.05 - $16.55
|
|
$17.70 - $18.10
|
SG&A
|
|
$ 4.29
|
|
$ 3.00
|
|
$ 2.87
|
|
$2.70 - $3.00
|
|
$3.00 - $3.30
|
Exploration††
|
|
$ 0.76
|
|
$ 0.30
|
|
$ 0.08
|
|
$0.15 - $0.25
|
|
$0.25 - $0.35
|
Interest ($mm)
|
|
$ 9.0
|
|
$ 9.1
|
|
$ 9.9
|
|
$9.5 - $10.5
|
|
$38.0 - $39.0
|
Effective tax rate
|
|
32%
|
|
35%
|
|
36%
|
|
36% - 38%
|
|
37% - 39%
|
|
|
|
|
|
|
|
|
|
|
|
* Production costs, marketing & transportation **
% of revenues, excluding hedges † 4Q17 and CY17 does
not include estimate of 4Q17 DD&A look-back adjustment ††
Includes seismic, delay rentals, etc.
LOE per boe in CY17 is estimated to range from $4.95-$5.25 in the
Delaware Basin, $5.50-$5.80 in the Midland Basin, and $18.20-$18.50 in
the Central Basin Platform. Production and ad valorem taxes in CY17, as
a percent of revenues excluding hedges, are estimated to be 6.2 percent
in the Delaware Basin, 6.2 percent in the Midland Basin, and 7.3 percent
in the Central Basin Platform. SG&A per boe in CY17 is estimated to be
comprised of cash and other of $2.55-$2.65 per boe and non-cash,
equity-based compensation of $0.45-$0.65 per boe.
Hedges
Energen recently added some 1.1 mmbo of 2018 WTI Midland to WTI Cushing
(sweet oil) differential hedges at an average price of $(0.60) per
barrel. The company also has initiated hedging for its estimated 2019
oil production and Midland to Cushing sweet oil differential.
For the last three months of 2017, 64 percent of the company’s estimated
oil production of 5.0 mmbo is hedged. Swaps for 2.0 mmbo have an average
NYMEX price of $50.68 per barrel, and 3-way collars for 1.2 mmbo have
average call, put, and short put prices of $62.18, $45.00, and $35.00
per barrel, respectively. Approximately 36 percent of Energen’s
estimated NGL production is hedged at an average price of $0.57 per
gallon, and 47 percent of its estimated gas production is hedged at an
average NYMEX-equivalent price of $3.36 per Mcf. Energen also has hedged
the WTI Midland to WTI Cushing (sweet oil) differential for 3.0 million
barrels at an average price of $(0.68) per barrel; approximately 88
percent of Energen’s oil production for the remainder of the year is
estimated to be sweet.
Basis Differentials
Energen’s average realized prices in the last three months of CY17 will
reflect commodity and basis hedges, oil transportation charges of
approximately $1.97 per barrel, NGL T&F fees of approximately $0.13 per
gallon, and basis differentials applicable to unhedged production.
Natural gas and NGL production also is subject to a percent of proceeds
contract of approximately 85%.
The assumed gas basis for all open contracts for November-December 2017
is $(0.45) per Mcf, and assumed prices for unhedged Midland to Cushing
basis differentials for sweet and sour oil (November-December) are
$(1.00) and $(1.30), respectively. Energen’s assumed commodity prices
for unhedged production are approximately $51.46 per barrel of oil
(October-December), $0.76 per gallon of NGL (October-December), and
$2.93 per Mcf of gas (November-December).
Estimated Price Realizations (pre-hedge):
|
|
4Q17
|
Crude oil (% of NYMEX/WTI)
|
|
94
|
NGL (after T&F) (% of NYMEX/WTI)
|
|
44
|
Natural gas (% of NYMEX/Henry Hub)
|
|
72
|
|
|
|
2018 Hedges
Oil
|
|
2018 Hedge Volumes
|
|
Avg. NYMEX Price
|
Three-way Collars
|
|
13.5 mmbo
|
|
|
Call Price
|
|
|
|
$ 60.04 per barrel
|
Put Price
|
|
|
|
$ 45.47 per barrel
|
Short Put Price
|
|
|
|
$ 35.47 per barrel
|
|
|
|
|
|
Commodity
|
|
Hedge Volumes
|
|
NYMEXe Price
|
NGL
|
|
105.8 mm gallons
|
|
$ 0.59 per gallon
|
Natural Gas
|
|
3.6 bcf
|
|
$ 3.19 per mcf
|
Energen also has hedged the Midland to Cushing differential on 10.8
million barrels of its estimated 2018 sweet oil production at an average
price of $(1.01).
2019 Hedges
Oil
|
|
2019 Hedge Volumes
|
|
Avg. NYMEX Price
|
Three-way Collars
|
|
1.4 mmbo
|
|
|
Call Price
|
|
|
|
$ 58.61 per barrel
|
Put Price
|
|
|
|
$ 45.00 per barrel
|
Short Put Price
|
|
|
|
$ 35.00 per barrel
|
|
|
|
|
|
Energen also has hedged the Midland to Cushing differential on 1.4
million barrels of its estimated 2019 sweet oil production at an average
price of $(0.53).
Conference Call
3Q17 slides associated with Energen’s quarterly release and conference
call are available at www.energen.com.
Energen will hold its quarterly conference call Wednesday, November 8,
at 8:30 a.m. EDT. 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, certain prior period losses associated with a
reduction in force, and income associated with divestitures. 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 9/30/17
|
|
Energen Net Income ($ in millions except per share data)
|
|
Net Income
|
|
Per Diluted Share
|
|
Net Income (Loss) All Operations (GAAP)
|
|
(18.5
|
)
|
|
|
|
(0.19
|
)
|
|
|
Non-cash mark-to-market losses (net of $22.1 tax)
|
|
40.2
|
|
|
|
|
0.41
|
|
|
|
Asset impairment, other (net of tax)
|
|
0.1
|
|
|
|
|
nm
|
|
|
|
Income associated with property sales (net of $2.0 tax)
|
|
(2.5
|
)
|
|
|
|
(0.03
|
)
|
|
|
Adjusted Income from Continuing Operations (Non-GAAP)
|
|
19.2
|
|
|
|
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended 9/30/16
|
|
Energen Net Income ($ in millions except per share data)
|
|
Net Income
|
|
Per Diluted Share
|
|
Net Income (Loss) All Operations (GAAP)
|
|
53.3
|
|
|
|
|
0.55
|
|
|
|
Non-cash mark-to-market gains (net of $8.9 tax)
|
|
(16.1
|
)
|
|
|
|
(0.17
|
)
|
|
|
Asset impairment, other (net of $0.3 tax)
|
|
0.3
|
|
|
|
|
nm
|
|
|
|
Reduction in force expenses (net of $0.2 tax)
|
|
0.3
|
|
|
|
|
nm
|
|
|
|
Income associated property sales (net of $32.3 tax)
|
|
(59.2
|
)
|
|
|
|
(0.61
|
)
|
|
|
Adjusted Income from Continuing Operations (Non-GAAP)
|
|
(21.4
|
)
|
|
|
|
(0.22
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Note: Amounts may not sum due to rounding
|
|
|
|
|
Non-GAAP Financial Measures
|
|
Earnings before interest, taxes, depreciation, depletion,
amortization and exploration expenses (EBITDAX) is a Non-GAAP
financial measure (GAAP refers to generally accepted accounting
principles). Adjusted EBITDAX from continuing operations further
excludes impairment losses, certain non-cash mark-to-market
derivative financial instruments, prior period losses associated
with a reduction in force, and income associated with divestitures.
Energen believes these measures allow analysts and investors to
understand the financial performance of the company from core
business operations, without including the effects of capital
structure, tax rates and depreciation. Further, this measure is
useful in comparing the company and other oil and gas producing
companies.
|
|
|
|
|
|
|
|
Reconciliation To GAAP Information
|
|
Three Months Ended 9/30
|
|
($ in millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Energen Net Income (Loss) (GAAP)
|
|
(18.5
|
)
|
|
53.3
|
|
Income associated with property sales, net of tax*
|
|
(2.5
|
)
|
|
(59.2
|
)
|
Net Income (Loss) Excluding Property Sales (Non-GAAP)
|
|
(21.0
|
)
|
|
(5.9
|
)
|
Interest expense
|
|
9.9
|
|
|
9.0
|
|
Income tax expense (benefit) **
|
|
(11.2
|
)
|
|
(3.9
|
)
|
Depreciation, depletion and amortization **
|
|
131.8
|
|
|
108.0
|
|
Accretion expense **
|
|
1.5
|
|
|
1.6
|
|
Exploration expense **
|
|
0.6
|
|
|
nm
|
|
Adjustment for asset impairment
|
|
0.1
|
|
|
0.6
|
|
Adjustment for mark-to-market (gains)/ losses
|
|
62.3
|
|
|
(25.0
|
)
|
Adjustment for reduction in force expenses
|
|
0.0
|
|
|
0.5
|
|
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)
|
|
174.0
|
|
|
84.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Three Months
Ended 9/30/2016.
|
|
|
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 September 30, 2016
|
(in thousands except per share and production data)
|
|
|
|
|
|
|
|
|
GAAP
|
|
2016 Property Sales
|
|
Non-GAAP
|
Revenues
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas sales
|
|
$
|
163,973
|
|
|
$
|
2,162
|
|
|
|
$
|
161,811
|
|
Gain (loss) on derivative instruments
|
|
|
20,412
|
|
|
|
-
|
|
|
|
|
20,412
|
|
Total Revenues
|
|
|
184,385
|
|
|
|
2,162
|
|
|
|
|
182,223
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production
|
|
|
42,280
|
|
|
|
1,253
|
|
|
|
|
41,027
|
|
Production and ad valorem taxes
|
|
|
10,987
|
|
|
|
621
|
|
|
|
|
10,366
|
|
O&G Depreciation, depletion and amortization
|
|
|
106,989
|
|
|
|
215
|
|
|
|
|
106,774
|
|
FF&E Depreciation, depletion and amortization
|
|
|
1,178
|
|
|
|
-
|
|
|
|
|
1,178
|
|
Asset impairment
|
|
|
587
|
|
|
|
-
|
|
|
|
|
587
|
|
Exploration
|
|
|
18
|
|
|
|
6
|
|
|
|
|
12
|
|
General and administrative †
|
|
|
21,710
|
|
|
|
(53
|
)
|
|
|
|
21,763
|
|
Accretion of discount on asset retirement obligations
|
|
1,556
|
|
|
|
1
|
|
|
|
|
1,555
|
|
(Gain) loss on sale of assets and other
|
|
|
(91,222
|
)
|
|
|
(91,371
|
)
|
|
|
|
149
|
|
Total costs and expenses
|
|
|
94,083
|
|
|
|
(89,328
|
)
|
|
|
|
183,411
|
|
Operating Income (Loss)
|
|
|
90,302
|
|
|
|
91,490
|
|
|
|
|
(1,188
|
)
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(8,987
|
)
|
|
|
-
|
|
|
|
|
(8,987
|
)
|
Other income
|
|
|
421
|
|
|
|
12
|
|
|
|
|
409
|
|
Total other expense
|
|
|
(8,566
|
)
|
|
|
12
|
|
|
|
|
(8,578
|
)
|
|
|
|
|
|
|
|
|
Loss Before Income Taxes
|
|
|
81,736
|
|
|
|
91,502
|
|
|
|
|
(9,766
|
)
|
Income tax expense (benefit)
|
|
|
28,422
|
|
|
|
32,289
|
|
|
|
|
(3,867
|
)
|
Net Income (Loss)
|
|
$
|
53,314
|
|
|
$
|
59,213
|
|
|
|
$
|
(5,899
|
)
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Average Common Share
|
|
$
|
0.55
|
|
|
$
|
0.60
|
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
Basic earning Per Average Common Share
|
|
$
|
0.55
|
|
|
$
|
0.60
|
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
Oil
|
|
|
3,325
|
|
|
|
30
|
|
|
|
|
3,295
|
|
NGL
|
|
|
980
|
|
|
|
22
|
|
|
|
|
958
|
|
Natural Gas
|
|
|
993
|
|
|
|
43
|
|
|
|
|
950
|
|
Total Production (mboe)
|
|
|
5,298
|
|
|
|
95
|
|
|
|
|
5,203
|
|
Total Production (boepd)
|
|
|
57,587
|
|
|
|
1,033
|
|
|
|
|
56,554
|
|
|
|
|
|
|
|
|
|
Note: Amounts may not sum due to rounding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
† General and administrative includes $515 of expense related to
the reductions in force
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
For the 3 months ending September 30, 2017 and 2016
|
|
|
|
|
|
|
|
|
3rd Quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share data)
|
|
|
2017
|
|
|
|
2016
|
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas sales
|
|
$
|
249,114
|
|
|
$
|
163,973
|
|
|
$
|
85,141
|
|
Gain (loss) on derivative instruments, net
|
|
|
(57,610
|
)
|
|
|
20,412
|
|
|
|
(78,022
|
)
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
191,504
|
|
|
|
184,385
|
|
|
|
7,119
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production
|
|
|
44,549
|
|
|
|
42,280
|
|
|
|
2,269
|
|
Production and ad valorem taxes
|
|
|
15,326
|
|
|
|
10,987
|
|
|
|
4,339
|
|
Depreciation, depletion and amortization
|
|
|
131,756
|
|
|
|
108,167
|
|
|
|
23,589
|
|
Asset impairment
|
|
|
100
|
|
|
|
587
|
|
|
|
(487
|
)
|
Exploration
|
|
|
625
|
|
|
|
18
|
|
|
|
607
|
|
General and administrative (including stock based compensation
of $4,713 and $6,518 for the three months ended September 30,
2017, and 2016, respectively)
|
|
|
21,474
|
|
|
|
21,710
|
|
|
|
(236
|
)
|
Accretion of discount on asset retirement obligations
|
|
|
1,473
|
|
|
|
1,556
|
|
|
|
(83
|
)
|
Gain on sale of assets and other
|
|
|
(5,977
|
)
|
|
|
(91,222
|
)
|
|
|
85,245
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
209,326
|
|
|
|
94,083
|
|
|
|
115,243
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
(17,822
|
)
|
|
|
90,302
|
|
|
|
(108,124
|
)
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(9,928
|
)
|
|
|
(8,987
|
)
|
|
|
(941
|
)
|
Other income
|
|
|
58
|
|
|
|
421
|
|
|
|
(363
|
)
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(9,870
|
)
|
|
|
(8,566
|
)
|
|
|
(1,304
|
)
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
|
|
(27,692
|
)
|
|
|
81,736
|
|
|
|
(109,428
|
)
|
Income tax expense (benefit)
|
|
|
(9,206
|
)
|
|
|
28,422
|
|
|
|
(37,628
|
)
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
(18,486
|
)
|
|
$
|
53,314
|
|
|
$
|
(71,800
|
)
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Average Common Share
|
|
$
|
(0.19
|
)
|
|
$
|
0.55
|
|
|
$
|
(0.74
|
)
|
Basic Earnings Per Average Common Share
|
|
$
|
(0.19
|
)
|
|
$
|
0.55
|
|
|
$
|
(0.74
|
)
|
Diluted Average Common Shares Outstanding
|
|
|
97,198
|
|
|
|
97,511
|
|
|
|
(313
|
)
|
Basic Average Common Shares Outstanding
|
|
|
97,198
|
|
|
|
97,068
|
|
|
|
130
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
For the 9 months ending September 30, 2017 and 2016
|
|
|
|
|
|
|
|
|
Year-to-date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per share data)
|
|
|
2017
|
|
|
|
2016
|
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas sales
|
|
$
|
644,212
|
|
|
$
|
458,374
|
|
|
$
|
185,838
|
|
Gain (loss) on derivative instruments, net
|
|
|
45,037
|
|
|
|
(40,005
|
)
|
|
|
85,042
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
689,249
|
|
|
|
418,369
|
|
|
|
270,880
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production
|
|
|
129,746
|
|
|
|
132,847
|
|
|
|
(3,101
|
)
|
Production and ad valorem taxes
|
|
|
41,364
|
|
|
|
33,422
|
|
|
|
7,942
|
|
Depreciation, depletion and amortization
|
|
|
352,957
|
|
|
|
344,564
|
|
|
|
8,393
|
|
Asset impairment
|
|
|
1,589
|
|
|
|
220,612
|
|
|
|
(219,023
|
)
|
Exploration
|
|
|
6,259
|
|
|
|
1,780
|
|
|
|
4,479
|
|
General and administrative (including stock based compensation
of $11,101 and $14,493 for the nine months ended September 30,
2017, and 2016, respectively)
|
|
|
61,665
|
|
|
|
74,783
|
|
|
|
(13,118
|
)
|
Accretion of discount on asset retirement obligations
|
|
|
4,330
|
|
|
|
5,092
|
|
|
|
(762
|
)
|
Gain on sale of assets and other
|
|
|
(6,980
|
)
|
|
|
(252,097
|
)
|
|
|
245,117
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
590,930
|
|
|
|
561,003
|
|
|
|
29,927
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
|
98,319
|
|
|
|
(142,634
|
)
|
|
|
240,953
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(28,039
|
)
|
|
|
(27,858
|
)
|
|
|
(181
|
)
|
Other income
|
|
|
486
|
|
|
|
580
|
|
|
|
(94
|
)
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(27,553
|
)
|
|
|
(27,278
|
)
|
|
|
(275
|
)
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
|
|
70,766
|
|
|
|
(169,912
|
)
|
|
|
240,678
|
|
Income tax expense (benefit)
|
|
|
26,368
|
|
|
|
(56,869
|
)
|
|
|
83,237
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
44,398
|
|
|
$
|
(113,043
|
)
|
|
$
|
157,441
|
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Average Common Share
|
|
$
|
0.45
|
|
|
$
|
(1.21
|
)
|
|
$
|
1.66
|
|
Basic Earnings Per Average Common Share
|
|
$
|
0.46
|
|
|
$
|
(1.21
|
)
|
|
$
|
1.67
|
|
Diluted Average Common Shares Outstanding
|
|
|
97,678
|
|
|
|
93,602
|
|
|
|
4,076
|
|
Basic Average Common Shares Outstanding
|
|
|
97,176
|
|
|
|
93,602
|
|
|
|
3,574
|
|
|
|
|
|
|
|
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of September 30, 2017 and December 31, 2016
|
|
(in thousands)
|
|
|
September 30, 2017
|
|
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
252
|
|
$
|
|
386,093
|
Accounts receivable, net
|
|
|
129,219
|
|
|
|
73,322
|
Inventories, net
|
|
|
14,538
|
|
|
|
14,222
|
Derivative instruments
|
|
|
3,895
|
|
|
|
50
|
Income tax receivable
|
|
|
9,598
|
|
|
|
27,153
|
Prepayments and other
|
|
|
5,838
|
|
|
|
5,071
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
163,340
|
|
|
|
505,911
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
Oil and natural gas properties, net
|
|
|
4,633,512
|
|
|
|
4,016,683
|
Other property and equipment, net
|
|
|
45,198
|
|
|
|
44,869
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
|
4,678,710
|
|
|
|
4,061,552
|
|
|
|
|
|
|
|
|
Other postretirement assets
|
|
|
3,583
|
|
|
|
3,619
|
Noncurrent derivative instruments
|
|
|
1,064
|
|
|
|
−
|
Other assets
|
|
|
6,879
|
|
|
|
8,741
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
4,853,576
|
|
$
|
|
4,579,823
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Long-term debt due within one year
|
|
$
|
−
|
|
|
$
|
|
24,000
|
Accounts payable
|
|
|
101,819
|
|
|
|
|
65,031
|
Accrued taxes
|
|
|
14,585
|
|
|
|
|
7,252
|
Accrued wages and benefits
|
|
|
21,268
|
|
|
|
|
25,089
|
Accrued capital costs
|
|
|
67,176
|
|
|
|
|
79,988
|
Revenue and royalty payable
|
|
|
48,429
|
|
|
|
|
51,217
|
Derivative instruments
|
|
|
18,089
|
|
|
|
|
65,467
|
Other
|
|
|
11,402
|
|
|
|
|
20,160
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
282,768
|
|
|
|
|
338,204
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
765,759
|
|
|
|
|
527,443
|
Asset retirement obligations
|
|
|
86,643
|
|
|
|
|
81,544
|
Deferred income taxes
|
|
|
535,002
|
|
|
|
|
495,888
|
Noncurrent derivative instruments
|
|
|
2,962
|
|
|
|
|
3,006
|
Other long-term liabilities
|
|
|
7,162
|
|
|
|
|
13,136
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
1,680,296
|
|
|
|
|
1,459,221
|
|
|
|
|
|
|
|
|
|
Total Shareholders’ Equity
|
|
|
3,173,280
|
|
|
|
|
3,120,602
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
4,853,576
|
|
|
$
|
|
4,579,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 3 months ending September 30, 2017 and 2016
|
|
|
3rd 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
|
|
$
|
203,281
|
|
$
|
138,388
|
|
$
|
64,893
|
Natural gas liquids
|
|
|
25,508
|
|
|
12,067
|
|
|
13,441
|
Natural gas
|
|
|
20,325
|
|
|
13,518
|
|
|
6,807
|
Total
|
|
$
|
249,114
|
|
$
|
163,973
|
|
$
|
85,141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Open non-cash mark-to-market gains (losses) on derivative instruments
|
Oil
|
|
$
|
(46,395)
|
|
$
|
22,984
|
|
$
|
(69,379)
|
Natural gas liquids
|
|
|
(15,765)
|
|
|
(954)
|
|
|
(14,811)
|
Natural gas
|
|
|
(105)
|
|
|
2,992
|
|
|
(3,097)
|
Total
|
|
$
|
(62,265)
|
|
$
|
25,022
|
|
$
|
(87,287)
|
|
|
|
|
|
|
|
|
|
|
Closed gains (losses) on derivative instruments
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
5,388
|
|
$
|
(4,118)
|
|
$
|
9,506
|
Natural gas liquids
|
|
|
(1,923)
|
|
|
−
|
|
|
(1,923)
|
Natural gas
|
|
|
1,190
|
|
|
(492)
|
|
|
1,682
|
Total
|
|
$
|
4,655
|
|
$
|
(4,610)
|
|
$
|
9,265
|
Total revenues
|
|
$
|
191,504
|
|
$
|
184,385
|
|
$
|
7,119
|
|
|
|
|
|
|
|
|
|
|
Production volumes
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
4,510
|
|
|
3,325
|
|
|
1,185
|
Natural gas liquids (MMgal)
|
|
|
60.6
|
|
|
41.2
|
|
|
19.4
|
Natural gas (MMcf)
|
|
|
9,174
|
|
|
5,958
|
|
|
3,216
|
Total production volumes (MBOE)
|
7,483
|
|
|
5,298
|
|
|
2,185
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes
|
|
|
|
|
|
|
|
|
|
Oil (MBbl/d)
|
|
|
49.0
|
|
|
36.1
|
|
|
12.9
|
Natural gas liquids (MMgal/d)
|
|
|
0.7
|
|
|
0.4
|
|
|
0.3
|
Natural gas (MMcf/d)
|
|
|
99.7
|
|
|
64.8
|
|
|
34.9
|
Total average daily production volumes (MBOE/d)
|
|
|
81.3
|
|
|
57.6
|
|
|
23.7
|
|
|
|
|
|
|
|
|
|
|
Average realized prices excluding effects of open non-cash
mark-to-market derivative instruments
|
Oil (per barrel)
|
|
$
|
46.27
|
|
$
|
40.38
|
|
$
|
5.89
|
Natural gas liquids (per gallon)
|
|
$
|
0.39
|
|
$
|
0.29
|
|
$
|
0.10
|
Natural gas (per Mcf)
|
|
$
|
2.35
|
|
$
|
2.19
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
Average realized prices excluding effects of all derivative
instruments
|
Oil (per barrel)
|
|
$
|
45.07
|
|
$
|
41.62
|
|
$
|
3.45
|
Natural gas liquids (per gallon)
|
|
$
|
0.42
|
|
$
|
0.29
|
|
$
|
0.13
|
Natural gas (per Mcf)
|
|
$
|
2.22
|
|
$
|
2.27
|
|
$
|
(0.05)
|
|
|
|
|
|
|
|
|
|
|
Costs per BOE
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production expenses
|
|
$
|
5.95
|
|
$
|
7.98
|
|
$
|
(2.03)
|
Production and ad valorem taxes
|
|
$
|
2.05
|
|
$
|
2.07
|
|
$
|
(0.02)
|
Depreciation, depletion and amortization
|
|
$
|
17.61
|
|
$
|
20.42
|
|
$
|
(2.81)
|
Exploration expense
|
|
$
|
0.08
|
|
$
|
−
|
|
$
|
0.08
|
General and administrative
|
|
$
|
2.87
|
|
$
|
4.10
|
|
$
|
(1.23)
|
Capital expenditures (including acquisitions)
|
|
$
|
251,621
|
|
$
|
211,393
|
|
$
|
40,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 9 months ending September 30, 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
|
|
$
|
532,652
|
|
$
|
386,905
|
|
$
|
145,747
|
Natural gas liquids
|
|
|
59,776
|
|
|
34,584
|
|
|
25,192
|
Natural gas
|
|
|
51,784
|
|
|
36,885
|
|
|
14,899
|
Total
|
|
$
|
644,212
|
|
$
|
458,374
|
|
$
|
185,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Open non-cash mark-to-market gains (losses) on derivative instruments
|
|
|
Oil
|
|
$
|
42,730
|
|
$
|
(33,444)
|
|
$
|
76,174
|
Natural gas liquids
|
|
|
(4,148)
|
|
|
(954)
|
|
|
(3,194)
|
Natural gas
|
|
|
8,856
|
|
|
(1,462)
|
|
|
10,318
|
Total
|
|
$
|
47,438
|
|
$
|
(35,860)
|
|
$
|
83,298
|
|
|
|
|
|
|
|
|
|
|
Closed gains (losses) on derivative instruments
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
(470)
|
|
$
|
(5,321)
|
|
$
|
4,851
|
Natural gas liquids
|
|
|
(3,468)
|
|
|
−
|
|
|
(3,468)
|
Natural gas
|
|
|
1,537
|
|
|
1,176
|
|
|
361
|
Total
|
|
$
|
(2,401)
|
|
$
|
(4,145)
|
|
$
|
1,744
|
Total revenues
|
|
$
|
689,249
|
|
$
|
418,369
|
|
$
|
270,880
|
|
|
|
|
|
|
|
|
|
|
Production volumes
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
11,608
|
|
|
10,269
|
|
|
1,339
|
Natural gas liquids (MMgal)
|
|
|
146.0
|
|
|
126.0
|
|
|
20.0
|
Natural gas (MMcf)
|
|
|
22,500
|
|
|
20,700
|
|
|
1,800
|
Total production volumes (MBOE)
|
|
|
18,833
|
|
|
16,719
|
|
|
2,114
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes
|
|
|
|
|
|
|
|
|
|
Oil (MBbl/d)
|
|
|
42.5
|
|
|
37.5
|
|
|
5.0
|
Natural gas liquids (MMgal/d)
|
|
|
0.5
|
|
|
0.5
|
|
|
−
|
Natural gas (MMcf/d)
|
|
|
82.4
|
|
|
75.5
|
|
|
6.9
|
Total average daily production volumes (MBOE/d)
|
|
|
69.0
|
|
|
61.0
|
|
|
8.0
|
|
|
|
|
|
|
|
|
|
|
Average realized prices excluding effects of open non-cash
mark-to-market derivative instruments
|
|
|
Oil (per barrel)
|
|
$
|
45.85
|
|
$
|
37.16
|
|
$
|
8.69
|
Natural gas liquids (per gallon)
|
|
$
|
0.39
|
|
$
|
0.27
|
|
$
|
0.12
|
Natural gas (per Mcf)
|
|
$
|
2.37
|
|
$
|
1.84
|
|
$
|
0.53
|
|
|
|
|
|
|
|
|
|
|
Average realized prices excluding effects of all derivative
instruments
|
|
|
Oil (per barrel)
|
|
$
|
45.89
|
|
$
|
37.68
|
|
$
|
8.21
|
Natural gas liquids (per gallon)
|
|
$
|
0.41
|
|
$
|
0.27
|
|
$
|
0.14
|
Natural gas (per Mcf)
|
|
$
|
2.30
|
|
$
|
1.78
|
|
$
|
0.52
|
|
|
|
|
|
|
|
|
|
|
Costs per BOE
|
|
|
|
|
|
|
|
|
|
Oil, natural gas liquids and natural gas production expenses
|
|
$
|
6.89
|
|
$
|
7.94
|
|
$
|
(1.05)
|
Production and ad valorem taxes
|
|
$
|
2.20
|
|
$
|
2.00
|
|
$
|
0.20
|
Depreciation, depletion and amortization
|
|
$
|
18.74
|
|
$
|
20.61
|
|
$
|
(1.87)
|
Exploration expense
|
|
$
|
0.33
|
|
$
|
0.11
|
|
$
|
0.22
|
General and administrative
|
|
$
|
3.27
|
|
$
|
4.47
|
|
$
|
(1.20)
|
Capital expenditures (includes acquisitions)
|
|
$
|
971,867
|
|
$
|
428,443
|
|
$
|
543,424
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20171108005629/en/ Copyright Business Wire 2017
Source: Business Wire
(November 8, 2017 - 6:00 AM EST)
News by QuoteMedia
www.quotemedia.com
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